US20190338762A1 - Mobile Pump System - Google Patents
Mobile Pump System Download PDFInfo
- Publication number
- US20190338762A1 US20190338762A1 US16/401,464 US201916401464A US2019338762A1 US 20190338762 A1 US20190338762 A1 US 20190338762A1 US 201916401464 A US201916401464 A US 201916401464A US 2019338762 A1 US2019338762 A1 US 2019338762A1
- Authority
- US
- United States
- Prior art keywords
- pump
- fluid
- mobile
- trailer
- wellbore
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Abandoned
Links
- 239000012530 fluid Substances 0.000 claims abstract description 111
- 238000005086 pumping Methods 0.000 claims abstract description 48
- 238000000034 method Methods 0.000 claims abstract description 39
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 claims description 22
- 239000007789 gas Substances 0.000 claims description 21
- 238000004891 communication Methods 0.000 claims description 15
- 239000000126 substance Substances 0.000 claims description 12
- 239000003345 natural gas Substances 0.000 claims description 11
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 11
- 239000000654 additive Substances 0.000 claims description 8
- 230000000996 additive effect Effects 0.000 claims description 8
- 239000002283 diesel fuel Substances 0.000 claims description 8
- 239000003502 gasoline Substances 0.000 claims description 7
- 238000011144 upstream manufacturing Methods 0.000 claims description 7
- 238000004519 manufacturing process Methods 0.000 description 44
- 239000000446 fuel Substances 0.000 description 15
- 238000005553 drilling Methods 0.000 description 13
- 230000015572 biosynthetic process Effects 0.000 description 12
- 238000005755 formation reaction Methods 0.000 description 12
- 239000002828 fuel tank Substances 0.000 description 11
- 230000000638 stimulation Effects 0.000 description 8
- 238000002485 combustion reaction Methods 0.000 description 6
- 230000005540 biological transmission Effects 0.000 description 4
- 238000012423 maintenance Methods 0.000 description 4
- 238000012544 monitoring process Methods 0.000 description 4
- 238000003860 storage Methods 0.000 description 4
- 230000003750 conditioning effect Effects 0.000 description 3
- 239000000463 material Substances 0.000 description 3
- 230000008569 process Effects 0.000 description 3
- 230000008439 repair process Effects 0.000 description 3
- 239000004576 sand Substances 0.000 description 3
- ATUOYWHBWRKTHZ-UHFFFAOYSA-N Propane Chemical compound CCC ATUOYWHBWRKTHZ-UHFFFAOYSA-N 0.000 description 2
- 230000008901 benefit Effects 0.000 description 2
- 239000003638 chemical reducing agent Substances 0.000 description 2
- 230000006378 damage Effects 0.000 description 2
- 238000013461 design Methods 0.000 description 2
- 238000006073 displacement reaction Methods 0.000 description 2
- 230000000694 effects Effects 0.000 description 2
- 229930195733 hydrocarbon Natural products 0.000 description 2
- 150000002430 hydrocarbons Chemical class 0.000 description 2
- 239000003949 liquefied natural gas Substances 0.000 description 2
- 230000009467 reduction Effects 0.000 description 2
- 239000011435 rock Substances 0.000 description 2
- 238000009491 slugging Methods 0.000 description 2
- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical compound [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 description 1
- 239000004215 Carbon black (E152) Substances 0.000 description 1
- 244000007835 Cyamopsis tetragonoloba Species 0.000 description 1
- 229910000831 Steel Inorganic materials 0.000 description 1
- NINIDFKCEFEMDL-UHFFFAOYSA-N Sulfur Chemical compound [S] NINIDFKCEFEMDL-UHFFFAOYSA-N 0.000 description 1
- 239000002253 acid Substances 0.000 description 1
- 230000009471 action Effects 0.000 description 1
- 230000003213 activating effect Effects 0.000 description 1
- 238000007792 addition Methods 0.000 description 1
- 230000004075 alteration Effects 0.000 description 1
- 239000001273 butane Substances 0.000 description 1
- 229910052799 carbon Inorganic materials 0.000 description 1
- 239000004568 cement Substances 0.000 description 1
- 230000008859 change Effects 0.000 description 1
- 230000006835 compression Effects 0.000 description 1
- 238000007906 compression Methods 0.000 description 1
- 230000003247 decreasing effect Effects 0.000 description 1
- 239000003344 environmental pollutant Substances 0.000 description 1
- 239000000284 extract Substances 0.000 description 1
- 230000006870 function Effects 0.000 description 1
- 239000012535 impurity Substances 0.000 description 1
- 230000001939 inductive effect Effects 0.000 description 1
- 230000000977 initiatory effect Effects 0.000 description 1
- 238000002347 injection Methods 0.000 description 1
- 239000007924 injection Substances 0.000 description 1
- 239000011810 insulating material Substances 0.000 description 1
- 238000002955 isolation Methods 0.000 description 1
- 239000007788 liquid Substances 0.000 description 1
- 230000007257 malfunction Effects 0.000 description 1
- 238000002844 melting Methods 0.000 description 1
- 230000008018 melting Effects 0.000 description 1
- 238000005272 metallurgy Methods 0.000 description 1
- 238000003801 milling Methods 0.000 description 1
- 230000000116 mitigating effect Effects 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- IJDNQMDRQITEOD-UHFFFAOYSA-N n-butane Chemical compound CCCC IJDNQMDRQITEOD-UHFFFAOYSA-N 0.000 description 1
- OFBQJSOFQDEBGM-UHFFFAOYSA-N n-pentane Natural products CCCCC OFBQJSOFQDEBGM-UHFFFAOYSA-N 0.000 description 1
- 238000013021 overheating Methods 0.000 description 1
- 230000037361 pathway Effects 0.000 description 1
- 231100000719 pollutant Toxicity 0.000 description 1
- 229920002401 polyacrylamide Polymers 0.000 description 1
- 230000002265 prevention Effects 0.000 description 1
- 239000001294 propane Substances 0.000 description 1
- 238000011084 recovery Methods 0.000 description 1
- 230000004044 response Effects 0.000 description 1
- 230000003584 silencer Effects 0.000 description 1
- 239000007787 solid Substances 0.000 description 1
- 239000010959 steel Substances 0.000 description 1
- 229910052717 sulfur Inorganic materials 0.000 description 1
- 239000011593 sulfur Substances 0.000 description 1
- 239000000725 suspension Substances 0.000 description 1
- 238000012360 testing method Methods 0.000 description 1
Images
Classifications
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F04—POSITIVE - DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS FOR LIQUIDS OR ELASTIC FLUIDS
- F04D—NON-POSITIVE-DISPLACEMENT PUMPS
- F04D13/00—Pumping installations or systems
- F04D13/02—Units comprising pumps and their driving means
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E21B33/13—Methods or devices for cementing, for plugging holes, crevices or the like
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/25—Methods for stimulating production
- E21B43/26—Methods for stimulating production by forming crevices or fractures
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/25—Methods for stimulating production
- E21B43/26—Methods for stimulating production by forming crevices or fractures
- E21B43/2607—Surface equipment specially adapted for fracturing operations
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F04—POSITIVE - DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS FOR LIQUIDS OR ELASTIC FLUIDS
- F04B—POSITIVE-DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS
- F04B17/00—Pumps characterised by combination with, or adaptation to, specific driving engines or motors
- F04B17/03—Pumps characterised by combination with, or adaptation to, specific driving engines or motors driven by electric motors
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F04—POSITIVE - DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS FOR LIQUIDS OR ELASTIC FLUIDS
- F04B—POSITIVE-DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS
- F04B17/00—Pumps characterised by combination with, or adaptation to, specific driving engines or motors
- F04B17/06—Mobile combinations
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F04—POSITIVE - DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS FOR LIQUIDS OR ELASTIC FLUIDS
- F04D—NON-POSITIVE-DISPLACEMENT PUMPS
- F04D13/00—Pumping installations or systems
- F04D13/02—Units comprising pumps and their driving means
- F04D13/06—Units comprising pumps and their driving means the pump being electrically driven
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F04—POSITIVE - DISPLACEMENT MACHINES FOR LIQUIDS; PUMPS FOR LIQUIDS OR ELASTIC FLUIDS
- F04D—NON-POSITIVE-DISPLACEMENT PUMPS
- F04D29/00—Details, component parts, or accessories
- F04D29/60—Mounting; Assembling; Disassembling
- F04D29/605—Mounting; Assembling; Disassembling specially adapted for liquid pumps
Definitions
- the present disclosure relates to a mobile pump system and a method for performing a pressure pumping application.
- Pressure pumping includes a propagation of fractures through layers of rock using pressurized fluid and/or pumping cement into a wellbore to complete it.
- pressure pumping to extract oil and/or gas trapped in formations beneath the Earth's surface, drilling of a wellbore is required, and the oil and/or gas may be recovered and extracted through the wellbore.
- Various pumps may be used during the drilling and oil and/or gas recovery process.
- drilling may include forming horizontal laterals extending out from a vertical section of the wellbore.
- the formation defining the vertical or lateral section may be fractured in sections, such that a fracture stimulation treatment is completed in the first section before moving on to apply a fracture stimulation treatment on a second section.
- This may be performed using a plug-and-perf technique in which a perforating gun is used to initiate fractures in the formation in the section after a plug is positioned between the first section and the second section. The plug seals the first section of the lateral from the other sections.
- This plug-and-perf technique is repeated for each section of the lateral until all intended sections of the lateral are perforated and fracture stimulated.
- the plug may be positioned at a predetermined location along the lateral by utilizing a pump system to pump a fluid into the wellbore, which exerts a pressure on the plug.
- the pressure on the plug moves the plug along the lateral to the desired position.
- Positioning the plug using the pump is considered an ancillary application, commonly referred to as “pumpdown”.
- Existing pumps used in pressure pumping application have numerous drawbacks.
- existing pumps use an internal combustion engine driven by diesel fuel, which have high carbon footprints.
- these existing pumps are cumbersome and require considerable room at the well site.
- these existing pumps do not allow for sufficiently precise control of flow rate, making it difficult to move the plug to the desired position.
- Existing pumps are expensive to acquire and maintain, and they create significant noise at a decibel level that is known to harm human hearing without adequate ear protection.
- existing pumping systems utilized in pressure pumping applications are not capable of sufficiently low flow rates or precise control of the flow rate.
- the existing pump systems lack precise control and the ability to operate at lower flow rates because they utilize conventional transmissions that are incapable of smooth increase or decrease in pumping rates. This may be the result of hesitation and slugging common when primary gears disengage and engage the secondary shaft. As a result, existing pressure pumping systems do not effectively remedy screen outs occurring during hydraulic fracturing applications.
- the present disclosure is directed to a mobile pump system including: a trailer movable by a vehicle; and a pump mounted to the trailer, the pump configured to pump a fluid.
- the pump includes an electrically-driven motor mounted to the trailer or is turbine powered by a turbine mounted to the trailer.
- the pump may be configured to pump the fluid into a wellbore at a tie-in point upstream of a wellhead of the wellbore.
- the fluid may include water and/or a chemical additive.
- the pump may include an auger or impeller configured to move the fluid.
- the pump may not be permanently installed at a site for performing a pressure pumping application.
- the electrically-driven motor may be fueled by a battery, natural gas, diesel fuel, or gasoline.
- the pump may be configured to adjust a flow rate of the pump by 1/10th of a bpm.
- the pump may be in fluid communication with a wellbore.
- the turbine may be operated using field gas.
- the mobile pump system may include plurality of pumps mounted to the trailer, where each pump may include an electrically-driven motor mounted to the trailer or may be turbine powered by a turbine mounted on the trailer.
- the mobile pump system may include controller configured to remotely control the pump.
- the controller may include a portable computing device.
- the pump may be configured to pump the fluid at a flow rate as low as 0.1 bpm.
- the turbine may include a direct coupled gear connection.
- the present disclosure is also directed to a method for performing a pressure pumping application including: providing a mobile pump system including: a trailer movable by a vehicle; and a pump mounted to the trailer, the pump configured to pump a fluid, where the pump includes an electrically-driven motor mounted to the trailer or is turbine powered by a turbine mounted to the trailer.
- the method may include pumping the fluid from a fluid container into a wellbore using the pump to move the fluid from the fluid container into the wellbore.
- the method may include positioning a plug in a lateral of the wellbore using the fluid pumped into the wellbore.
- the pump may be configured to pump the fluid into the wellbore at a tie-in point upstream of a wellhead of the wellbore.
- the fluid may include water and/or a chemical additive.
- the pump may include an auger or impeller configured to move the fluid.
- the pump may not be permanently installed at a site for performing a pressure pumping application.
- the electrically-driven motor may be fueled by a battery, natural gas, diesel fuel, or gasoline.
- the pump may be configured to adjust a flow rate by 1/10th of a bpm.
- the pump may be in fluid communication with a wellbore.
- the turbine may be operated using field gas.
- the pump may be configured to pump the fluid at a flow rate as low as 0.1 bpm.
- the pump may be remotely controlled by a controller.
- the controller may include a portable computing device.
- the pump may be configured to pump the fluid at a flow rate of up to 140 barrels per minute (bpm) at a pressure of up to 20,000 psi.
- a mobile pump system comprising: a trailer movable by a vehicle; and a pump mounted to the trailer, the pump configured to pump a fluid, wherein the pump comprises an electrically-driven motor mounted to the trailer or is turbine powered by a turbine mounted to the trailer.
- Clause 2 The mobile pump system of clause 1, wherein the pump is configured to pump the fluid into a wellbore at a tie-in point upstream of a wellhead of the wellbore.
- Clause 3 The mobile pump system of clause 1 or 2, wherein the fluid comprises water and/or a chemical additive.
- Clause 4 The mobile pump system of any of clauses 1-3, wherein the pump comprises an auger or impeller configured to move the fluid.
- Clause 5 The mobile pump system of any of clauses 1-4, wherein the pump is not permanently installed at a site for performing a pressure pumping application.
- Clause 6 The mobile pump system of any of clauses 1-5, wherein the electrically-driven motor is fueled by a battery, natural gas, diesel fuel, or gasoline.
- Clause 7 The mobile pump system of any of clauses 2-6, wherein the pump is configured to adjust a flow rate of the pump by 1/10th of a bpm.
- Clause 8 The mobile pump system of any of clauses 1-7, wherein the pump is in fluid communication with a wellbore.
- Clause 9 The mobile pump system of any of clauses 1-8, wherein the turbine is operated using field gas.
- Clause 10 The mobile pump system of any of clauses 1-9, comprising a plurality of pumps mounted to the trailer, wherein each pump comprises an electrically-driven motor mounted to the trailer or is turbine powered by a turbine mounted on the trailer.
- Clause 11 The mobile pump system of any of clauses 1-10, further comprising a controller configured to remotely control the pump.
- Clause 12 The mobile pump system of clause 11, wherein the controller comprises a portable computing device.
- Clause 13 The mobile pump system of any of clauses 1-12, wherein the pump is configured to pump the fluid at a flow rate as low as 0.1 bpm.
- Clause 14 The mobile pump system of any of clauses 1-13, wherein the turbine comprises a direct coupled gear connection.
- Clause 15 The mobile pump system of any of clauses 1-14, wherein the pump is configured to pump the fluid at a flow rate of up to 140 barrels per minute (bpm) at a pressure of up to 20,000 psi.
- a method for performing a pressure pumping application comprising: providing a mobile pump system comprising: a trailer movable by a vehicle; and a pump mounted to the trailer, the pump configured to pump a fluid, wherein the pump comprises an electrically-driven motor mounted to the trailer or is turbine powered by a turbine mounted to the trailer.
- Clause 17 The method of clause 16, further comprising: pumping the fluid from a fluid container into a wellbore using the pump to move the fluid from the fluid container into the wellbore.
- Clause 18 The method of clause 17, further comprising: positioning a plug in a lateral of the wellbore using the fluid pumped into the wellbore.
- Clause 19 The method of any of clauses 16-18, wherein the pump is configured to pump the fluid into the wellbore at a tie-in point upstream of a wellhead of the wellbore.
- Clause 20 The method of any of clauses 16-19, wherein the fluid comprises water and/or a chemical additive.
- Clause 21 The method of any of clauses 16-20, wherein the pump comprises an auger or impeller configured to move the fluid.
- Clause 22 The method of any of clauses 16-21, wherein the pump is not permanently installed at a site for performing a pressure pumping application.
- Clause 23 The method of any of clauses 16-22, wherein the electrically-driven motor is fueled by a battery, natural gas, diesel fuel, or gasoline.
- Clause 24 The method of any of clauses 16-23, wherein the pump is configured to adjust a flow rate by 1/10th of a bpm.
- Clause 25 The method of any of clauses 16-24, wherein the pump is in fluid communication with a wellbore.
- Clause 26 The method of any of clauses 16-25, wherein the turbine is operated using field gas.
- Clause 27 The method of any of clauses 16-26, wherein the pump is configured to pump the fluid at a flow rate as low as 0.1 bpm.
- Clause 28 The method of any of clauses 16-27, wherein the pump is remotely controlled by a controller.
- Clause 29 The method of clause 28, wherein the controller comprises a portable computing device.
- Clause 30 The method of any of clauses 16-29, wherein the pump is configured to pump the fluid at a flow rate of up to 140 barrels per minute (bpm) at a pressure of up to 20,000 psi.
- FIG. 1 shows a schematic cross-sectional view of the Earth at an oil and/or gas production site utilizing horizontal drilling techniques
- FIG. 2 shows another schematic cross-sectional view of the Earth at an oil and/or gas production site utilizing horizontal drilling techniques and a mobile pump system;
- FIG. 3 shows a schematic aerial view of a well pad at an oil and/or gas production site, the well pad including a mobile pump system;
- FIG. 4 shows a schematic side view of a mobile pump system according having a trailer and a cab for moving the mobile pump system;
- FIG. 5 shows a schematic top view of a mobile pump system including the trailer and the electrically-driven pump or turbine-driven pump
- FIG. 6 shows a schematic side view of an auger-style pump of a mobile pump system
- FIG. 7 shows a controller for controlling a mobile pump system
- FIG. 8 shows a schematic top view of a mobile pump system including a pump driven by an electric motor
- FIG. 9 shows a schematic perspective view of a mobile pump system including a pump driven by a turbine
- FIG. 10 shows a schematic perspective view of a mobile pump system including a pump driven by a turbine, with the trailer including a fuel tank;
- FIG. 11 shows a schematic top view of a mobile pump system including a secondary pump.
- the present disclosure is directed to a mobile pump system that includes: a trailer movable by a vehicle; and a pump mounted to the trailer, the pump configured to pump a fluid, wherein the pump comprises an electrically-driven motor mounted to the trailer or is turbine powered by a turbine mounted to the trailer.
- the mobile pump system described herein may be suitable for pressure pumping applications.
- an oil and/or gas production site 10 is shown.
- the surface 11 Earth's surface
- the wellbore 12 includes a wellhead 13 , which is a structural component at the surface 11 of the wellbore 12 which provides a structural and pressure-containing interface for various drilling and production equipment.
- the production site 10 may be a site for conducting hydraulic fracturing.
- the production site 10 may utilize a horizontal drilling technique in which at least one lateral 14 is used.
- the wellbore 12 may include a vertical region of 2,500 to 25,000, such as 6,000 to 15,000 or 6,000 to 10,000 feet in depth, although the length of this vertical region is not limited to this range.
- the wellbore 12 may include a leveling-off point 16 in which the vertical region ends and the lateral 14 is drilled horizontally in the Earth (the lateral 14 may have approximately the same depth from the surface 11 at all points).
- Each lateral 14 may have a length of 2,500-25,000, such as 3,000 to 10,000 feet, as measured from the leveling-off point 16 to an end 18 of the lateral 14 , although the length of the lateral 14 is not limited to this range. It will be appreciated that FIG. 1 is not drawn to scale, but merely provides a useful schematic of a production site 10 performing horizontal drilling.
- the lateral 14 may include a plurality of regions, which are of a predetermined length. Hydraulic fracture stimulation treatment may be performed in the lateral 14 individually at each region. Hydraulic fracture stimulation treatment includes pumping a fracturing fluid into the formation.
- the lateral 14 of the schematic in FIG. 1 includes a first region 20 , a second region 22 , a third region 24 , a fourth region 26 , a fifth region 28 , and a sixth region 30 .
- the production site 10 may utilize a “plug-and-perf” method for hydraulic fracture stimulation treatment.
- hydraulic fracture stimulation treatment has been completed for the first region 20 .
- a fractured first region 32 was created in the formation at the first region 20 .
- a first plug 34 was positioned at an end of the first region 20 closest to the wellhead 13 (a proximal end of the first region 20 ). Once in place, this first plug 34 may prevent fluid subsequently pumped into the wellbore 12 from entering the first region 20 .
- hydraulic fracture stimulation treatment in the second region 22 of the formation may be initiated by lowering a perforating gun 36 (hereinafter “perf gun”) into the wellbore 12 and positioning the perf gun 36 in the second region 22 .
- the perf gun 36 may be lowered into the wellbore 12 using a perf trailer 37 .
- charges of the perf gun 36 may be detonated so as to create multiple connection points from the wellbore 12 to the formation in the second region 22 .
- Oil and/or gas may be extracted by escaping from fractures and extracted to the surface 11 via the wellbore 12 .
- FIG. 2 the production site 10 is shown at a time after that depicted in FIG. 1 .
- the fractured second region 38 is shown, which was created by the perf gun 36 from FIG. 1 .
- FIG. 2 is also not drawn to scale, but merely provides a useful schematic of a production site 10 performing horizontal and/or vertical drilling.
- a second plug 40 is being lowered into the wellbore 12 by a plug trailer 41 to be positioned at a proximal position of the second region 22 (on the end of the second region 22 closer to the wellhead 13 ).
- the second plug 40 is spaced apart from the first plug 34 by approximately the length of the second region 22 .
- the second plug 40 may be positioned using positioning fluid 42 to provide pressure to the second plug 40 to move the second plug along the length of the wellbore 12 (including the lateral 14 ).
- the positioning fluid 42 may include water and/or a chemical additive.
- the chemical additive may include a friction reducer to reduce surface tension.
- the chemical additive may reduce tension or pipe friction along the wellbore 12 associated with positioning the second plug 40 .
- the second plug 40 may be positioned using the mobile pump system 44 of the present disclosure.
- the mobile pump system 44 may be used to position the second plug 40 as merely one non-limiting example of how the mobile pump system 44 may be used in a pressure pumping application.
- the mobile pump system 44 may be used to complete other pressure pumping applications using the components of the mobile pump system 44 described hereinafter.
- the mobile pump system 44 may include a trailer 46 movable by a vehicle (e.g., a cab having a fifth wheel).
- the trailer 46 may be movable by a vehicle, such as a cab, to and from the production site 10 .
- the mobile pump system 44 may be conveniently moved from location to location, such as to and from the production site 10 , and the mobile pump system 44 does not need to be permanently installed at the production site 10 .
- the trailer 46 may be separable/detachable from the vehicle such that the trailer 46 may be left at the production site 10 and the vehicle driven away, or the trailer 46 may be integrated with the vehicle, such that the vehicle remains at the production site 10 while the mobile pump system 44 is in use and drives away after use of the mobile pump system 44 is completed.
- the mobile pump system 44 may further include a pump 48 mounted to the trailer 46 .
- the pump 48 may be configured to pump the positioning fluid 42 into the wellbore 12 .
- the pump may include an electric motor 50 mounted to the trailer 46 or may be powered by a turbine 50 mounted to the trailer 46 .
- the trailer 46 may include multiple pumps 48 in some embodiments and may include multiple electric motors or turbines 50 for driving the pumps 48 .
- the term “electric motor” or “electrically-driven motor” refers to a motor in which electrical energy is converted into mechanical energy.
- the term “turbine” refers to a rotary mechanical device that extracts energy from a fluid (e.g., liquid and/or gas) flow and converts it into useful work to generate electrical energy to power the pump 48 .
- the trailer 46 may also include a power generator 52 in connection with the pump 48 to fuel the electrically-driven motor or the turbine 50 of the pump 48 .
- the power generator 52 may be battery, natural gas, diesel fuel, or gasoline fueled.
- the pump 48 may be driven by the electric motor or the turbine 50 and not by an internal combustion engine.
- the pump 48 may be configured to pump the positioning fluid 42 , or any other fluid, at a flow rate of up to 60 barrels per minute (bpm), such as up to 80 bpm, up to 100 bpm, up to 120 bpm, up to 140 bpm or higher.
- a barrel is defined as 42 US gallons, which is approximately 159 Liters.
- the pump 48 may be configured to pump the positioning fluid 42 at far lower flow rates, and may pump the positioning fluid 42 at a flow rate as low as 0.1 bpm (when the pump is not turned off such that it's flow rate would be 0 bpm).
- the pump 48 may be controlled such that its flow rate may be controlled within 1/10th of a bpm, resulting in a flow rate within 1/10th of a bpm compared to a predetermined flow rate.
- the pump may be configured to adjust the flow rate by 1/10th of a bpm (e.g., adjust the flow rate of the pump 48 from 60.0 bpm to 59.9 bpm or from 0.2 bpm to 0.1 bpm).
- Existing pressure pumping systems including ancillary pressure pumping applications, are not capable of such low flow rates or such precise control of the flow rate.
- the existing pump systems lack precise control and the ability to operate at lower flow rates because they utilize conventional transmissions that are incapable of smooth increase or decrease in pumping rates. This may be the result of hesitation and slugging common when primary gears disengage and engage the secondary shaft.
- the ability to pump at lower rates and to more precisely control the flow rate of the pump 48 may be especially useful in post-occurrence remedying of “screen outs,” which are common in hydraulic fracturing applications.
- a screen out occurs when proppant and fluid (of the positioning fluid 42 , for example) can no longer be injected into the formation. This may be due to resistant stresses of the formation becoming too excessive or surface-originated reasons resulting in loss of viscosity to carry proppant so that it falls out of suspension and plugs perforations in the wellbore 12 . In this way, the wellbore 12 becomes “packed” with proppant, which does not allow any further operations to continue due to high pressures that cannot be overcome from these blockages.
- the wellbore 12 may be opened at the surface 11 to relieve pressure and to carry at least some of the proppant out of the wellbore 12 and create a pathway to continue fluid injection to clear the wellbore 12 and allow operations to continue, which is a dangerous operation.
- An attempt to continue pumping operations at low rates to avoid reaching maximum pressure so that the proppant that is packed is forced through perforations and into the wellbore 12 may be attempted.
- the pump cannot pump at low enough rates to avoid again reaching maximum pressure.
- existing systems are often required to switch to a coiled tubing procedure to wash the proppant out and carry it back to the surface so that the wellbore 12 is finally clear.
- the coiled tubing procedure results in shutdown of operations for 3-4 days and is additionally expensive to complete.
- the ability to pump fluids at lower rates and to more precisely control the flow rate of the pump 48 may be especially useful in prevention or mitigation of the adiabatic effect which can cause wireline cable melting and/or failure during pump down operations, which are common in hydraulic fracturing applications.
- the wellhead is equipped with a lubricator and flow tubes to enable operations in a wellbore that can have pressure of several thousand pounds or more of pressure.
- the process of bringing the lubricator and the wellbore to the same pressure is known as “equalization.”
- the air in the lubricator compresses faster than it can be evacuated the adiabatic compression can cause the temperature to rise to as much as 1,200° F. ( ⁇ 650° C.).
- the lubricator may first be filled with fluid prior to equalizing; this practice can mitigate much of the air and therefore most of the energy to cause damage.
- the fluid In order to fill the lubricator with fluid without inducing wireline burn-up, the fluid must be introduced at very low rates so that the air can be evacuated at an equivalent rate so as not to introduce temperature increases caused by compressing air rapidly.
- the pump cannot pump at low enough rates to completely avoid against reaching damaging high temperatures.
- the pump 48 would be able to overcome this situation successfully because the electric motor or the turbine 50 of the pump 48 allows the pump 48 to inject fluid for displacement of the air in the lubricator at lower rates (as low as approximately 0.1 bpm) without the risks posed by existing systems.
- the pump 48 may be configured to pump fluid at a pressure of up to 20,000 psi, such as up to 15,000 psi, up to 12,000 psi, up to 10,000 psi, up to 8,000 psi, or up to 6,000 psi, although higher pressures are also contemplated.
- a fluid tank 54 containing the positioning fluid 42 may be in fluid communication with the pump 48 .
- the pump 48 may pump the positioning fluid 42 from the fluid tank 54 into the wellbore 12 to position the second plug 40 at a predetermined position in the wellbore 12 .
- the mobile pump system 44 may position the second plug 40 at a predetermined position in the wellbore 12 .
- the second plug 40 may be positioned in the wellbore by providing the previously-described mobile pump system 44 .
- the pump 48 of the mobile pump system 44 may be placed in fluid communication with the wellbore 12 .
- the positioning fluid 42 may be pumped from the fluid tank 54 into the wellbore 12 using the pump 48 .
- the positioning fluid 42 pumped into the wellbore 12 may exert a pressure on the second plug 40 so as to move the second plug 40 along the lateral 14 and into the predetermined position.
- the position of the second plug 40 may be monitored from the surface by any means known in the art.
- the flow rate of the positioning fluid 42 pumped by the pump 48 may be adjusted and controlled to position the second plug 40 .
- the flow rate may be increased or decreased to adjust the rate at which the second plug 40 is moved. For example, when the second plug 40 is proximate the predetermined position, the flow rate of positioning fluid 42 may be lowered so that the position of the second plug 40 can be more precisely selected.
- the mobile pump system 44 described herein may be used for any pressure pumping in which its characteristics are suitable and is not limited to the above-described application.
- the mobile pump system 44 may be used in hydraulic fracturing applications.
- Hydraulic fracturing applications include any application associated with hydraulic fracturing performed at a production site. Hydraulic fracturing refers to fluid injected down the wellbore through perforations exceeding the minimum fracture pressure needed to fracture the rock in the formation.
- An example of a hydraulic fracturing application includes ancillary applications (“pumpdown”), such as positioning a plug (previously described), drillout applications, injecting acid into the formation, pressure testing casing, injecting diverter materials, “toe preps” involving initiating the first fracture network in a well, and the like.
- Drillout applications may include applications performed after the drilling and fracturing process has concluded and the well is being prepared to deliver hydrocarbon production.
- a drillout application may include milling or drilling out plugs previously positioned in the laterals and removing debris from the milled plugs by pumping the debris from the plug location to the surface.
- the mobile pump system 44 allows for the reduction of capital costs compared to existing pump systems as the mobile pump system 44 requires less capital costs to build and operate.
- the mobile pump system 44 also significantly reduces repair and maintenance costs compared to existing systems.
- the use of the electric motor or turbine 50 to drive the pump 48 helps to reduce repair and maintenance costs.
- the electric motor or turbine 50 has a higher run time before requiring repairs compared to conventional internal combustion engines (motors) used in existing pumps, which are diesel driven, for example. Keeping the electric motor or turbine 50 cool and lubricated allows the electric motor or turbine 50 to have a longer running life compared to the motors used in existing systems.
- the electric motor or turbine 50 also run more efficiently compared to the motors used in existing systems, such as in terms of emissions and consumption of fuel.
- the mobile pump system 44 using the electric motor or turbine 50 to drive the pump 48 also requires significantly less fuel compared to existing systems.
- the electric motor or turbine 50 may utilize natural gas powered electric generation, such as the field gas available at a production site. Thus, sulfur and other pollutants that arise from diesel combustion in conventional internal combustion motors are not present in the combustion of natural gas powered electric generation.
- the inclusion of the electric motor or the turbine 50 in the mobile pump system 44 also reduces the noise associated with the mobile pump system 44 as pumps used in existing systems provide significant noise pollution and make it difficult to operate such pumps in residential areas (e.g., near housing plans, schools, hospitals, and the like).
- the mobile pump system 44 includes a more compact design of the pumps 48 compared with existing systems. Multiple pumps 48 may be included on the trailer 46 .
- the more compact system contributes to a safe production site 10 as there are less components at the production site 10 to cause a navigational and/or tripping hazard.
- This compact design also allows for the mobile pump system 44 to be set-up faster, resulting in less wasted time and faster time to production.
- the mobile pump system 44 may include multiple of at least on component included in the system, such as multiple pumps 48 , multiple electric motors or turbines 50 , multiple controllers 80 , and the like. The redundancy associated with certain of the components mounted on the trailer 46 of the mobile pump system 44 allows the system to avoid stopping operation of the pressure pumping application should one of the redundant components fail.
- the production site 10 includes a well pad 56 .
- the well pad 56 includes six wellbores 12 A- 12 F, each wellbore having a vertical region and at least one lateral traversing a direction different from the other wellbores of the well pad 56 .
- the non-limiting example of a pressure pumping application is being conducted at only the first wellbore 12 A; however, multiple well heads may be in production (e.g., conducting oilfield activity) simultaneously.
- the production site 10 may include at least one fracturing trailer 58 A- 58 F, each including at least one fracturing pump 60 A- 60 F.
- the production site 10 may further include sand and fracturing fluid storage tanks 62 , which include sand and fracturing fluid used to keep fractures in the formation open.
- the production site 10 may further include a water tank 64 for pumping water into the first wellbore 12 A.
- the water tank 64 may be in addition to or the same as the fluid tank 54 containing the positioning fluid 42 .
- the production site 10 may further include a chemical storage tank 66 , which may store any useful chemical, such as a friction reducer (e.g., polyacrylamide or a guar-based chemical).
- a friction reducer e.g., polyacrylamide or a guar-based chemical
- the fracturing pumps 60 A- 60 F may be in fluid communication with at least one of the sand and fracturing fluid storage tanks 62 , the water tank 64 , and the chemical storage tank 66 to pump the various materials and/or fluids contained therein into the first wellbore 12 A via piping 70 .
- the piping 70 may include an isolation valve 72 for isolating the fracturing pumps 60 A- 60 F from the first wellbore 12 A when the fracturing pumps 60 A- 60 F are not pumping fluid/material into the first wellbore 12 A.
- the production site 10 may further include a data monitoring station 68 , which may be used to monitor all operations conducted at the production site 10 and control those operations accordingly.
- the data monitoring station 68 may be remote from the production site 10 .
- production site 10 may further include the mobile pump system 44 A.
- the production site may include a single mobile pump system 44 A or multiple mobile pump systems 44 A- 44 B, as necessary.
- a first mobile pumping system 44 A is used to pump positioning fluid 42 into the first wellbore 12 A.
- the first mobile pumping system 44 A may include a first trailer 46 A, a first power generator 52 A, and a first pump 48 A having a first electric motor 50 A.
- the production site 10 may utilize a second mobile pumping system 44 B in addition to or in lieu of the first mobile pumping system 44 A.
- the second mobile pumping system 44 B may include a second trailer 46 B, a second power generator 52 B, and two pumps 48 B, 48 C, each having an electric motor 50 B, 50 C.
- the production site 10 may include the fluid tank 54 containing the positioning fluid 42 , and the fluid tank 54 may be in fluid communication with the first pump 48 A of the first mobile pumping system 44 A.
- the first mobile pumping system 44 A and the second mobile pumping system 44 B may be moved to and from the production site 10 without being permanently installed at the pumping site 10 .
- the first pump 48 A may be in fluid communication with the first wellbore 12 A so as to pump the positioning fluid 42 into the first wellbore 12 A.
- the first pump 48 A may be in fluid communication with the piping 70 so as to be in fluid communication with the first wellbore 12 A, and the first pump 48 A may intersect with the piping 70 at a tie-in point 74 .
- the tie-in point 74 may be upstream of the wellhead of the first wellbore 12 A (e.g., before the piping 70 reaches the wellhead of the first wellbore 12 A).
- a non-limiting example of the mobile pump system 44 may include a cab 76 .
- the cab 76 may be a truck capable of attaching the trailer 46 thereto (such as via a fifth wheel), so that the trailer 46 may be hauled to and from the production site 10 .
- the trailer 46 may be detachable from the cab 76 so that it may be left at the job site, or the trailer 46 may be an integrated part of the cab 76 (not detachable therefrom).
- the cab 76 is the power generator 52 because the cab may fuel the electric motor or turbine 50 used to drive the pump 48 .
- FIG. 5 a top view of a non-limiting example of the mobile pump system 44 is shown, with the mobile pump system 44 including the trailer 46 , the pump 48 having the electric motor 50 , and the power generator 52 .
- the power generator 52 may be connected to the pump 48 (e.g., the electric motor 50 ) to fuel the electric motor 50 , such that the electric motor 50 may drive the pump 48 .
- the pump 48 may be any pump suitable for pumping the positioning fluid 42 as previously described.
- the pump 48 may be an auger-style pump that includes an auger or impeller 78 driven by the electric motor or the turbine 50 to move the positioning fluid 42 into the wellbore 12 .
- the auger-style pump may provide certain advantages, including allowing for a more precise control of flow rate, reduced maintenance, and ease of maintenance (based on the reduced number and simplicity of components).
- the pump 48 , the electric motor or the turbine 50 , the generator 52 , and/or other components (“controllable components”) of the mobile pump system 44 may be controlled remotely by a controller 80 .
- “remotely” refers to a geographic location separate from the controllable component.
- the pump 48 may be controlled from the data monitoring station 68 or other location at the production site 10 (shown in FIG. 3 ), or the pump 48 may be controlled off-site (not at the production site 10 ).
- the pump 48 may be controlled by the controller 80 that is a portable computing device, such that the portable computing device may be moved between locations and is still able to control the pump 48 .
- the portable computing device may be, for instance, a laptop computer, a tablet computer, or a smartphone.
- relevant data associated with the mobile pump system 44 may be communicated to the controller 80 remote from the controllable component(s).
- GUI graphical user interface
- the GUI may allow the user to control various features of the controllable components. Non-limiting examples include controlling the pump's 48 flow rate or the pressure of the pump 48 .
- the GUI may display the flow rate and pressure of the pump 48 .
- the GUI may allow the user to turn the pump 48 on or off.
- the GUI may display the fill level of the fluid tank 54 or provide a status of the electric motor or the turbine 50 , such as whether any issues are identified with the electric motor or the turbine. It will be appreciated that other aspects of the mobile pump system 44 may be controlled by interacting with the GUI, and any suitable layout of the GUI may be used.
- Multiple controllable components e.g., multiple pumps
- the GUI may display on the controller various diagnostic and monitoring information.
- the GUI may display electric motor or the turbine temperature, fluid levels, and pump revolutions per minute.
- the mobile pump system 82 may include a trailer 84 attachable to a vehicle for moving the trailer 84 to various locations.
- the mobile pump system 82 may include a controller 86 mounted on the trailer 84 , the controller 86 in electrical communication with other components of the mobile pump system 82 (e.g., an electrical transformer 88 , a variable frequency drive 90 , a heat exchanger, an electric motor 94 , a pump 96 , a secondary pump 98 , and a secondary electric motor 100 ).
- the controller 86 may communicate control signals to the other components to cause the other components to perform a predetermined action (e.g., activating or deactivating a component, changing a pump rate, changing a heat exchanger temperature, and the like).
- the mobile pump system 82 may include an electrical transformer 88 mounted on the trailer 84 .
- the electrical transformer 88 may increase or decrease a voltage from an external power source for use by one of the components of the mobile pump system 82 . This may allow components of the mobile pump system 82 to be powered by an external power source not included on the trailer 84 by electrically connecting the external power source to the transformer 88 , which may be electrically connected to the other components.
- the mobile pump system 82 may include the variable frequency drive 90 mounted on the trailer 84 .
- the variable frequency drive 90 may include an electro-mechanical drive system to control motor speed and/or torque of the electric motor 94 by varying motor input frequency and/or voltage.
- the mobile pump system 82 may include the heat exchanger 92 mounted on the trailer 84 to regulate temperature of at least one of the other components (e.g., the electric motor 94 and/or the pump 96 ), such that the component can operate more efficiently.
- the heat exchanger 92 may function as a cooler to prevent a component of the mobile pump system 82 from overheating.
- the mobile pump system 82 may include the electric motor 94 mounted on the trailer 84 , the electric motor 94 as previously described herein.
- the mobile pump system 82 may also include the pump 96 a , 96 b (a single or multiple pumps may be included) mounted on the trailer 84 .
- the pump 96 a , 96 b may include the features previously described herein in connection with pump 48 .
- the pump 96 a , 96 b may be driven by the electric motor 94 .
- the mobile pump system 82 may include a secondary pump 98 and/or a secondary motor 100 (e.g., an electric motor) mounted on the trailer 84 .
- the secondary pump 98 may include a triplex pump.
- the secondary pump 98 may be configured for pumping fluid at higher pressure compared to the pump 96 a , 96 b of the mobile pump system 82 .
- the secondary pump 98 may be selectively activated in situations in which the mobile pump system 82 is required to operate at a higher pressure.
- the secondary pump 98 may be isolated from the pump 96 a , 96 b of the mobile pump system.
- the secondary motor 100 may drive the secondary pump 98 .
- the pump 96 a , 96 b and/or the secondary pump 98 may be in fluid communication with the wellbore 12 (see FIG. 2 ).
- a mobile pump system 102 may include any of the components discussed in connection with the mobile pump system 82 from FIG. 8 and may include any additional or alternative components as hereinafter described.
- the trailer 84 may include a connection portion 104 configured to engage with an engagement portion of a cab (e.g., a fifth wheel).
- the connection portion 104 may engage with a cab, such that the mobile pump system 102 may be transported by the cab to various locations, such as to and from a production site.
- the mobile pump system 102 may include an inlet filter silencer 106 mounted on the trailer 84 to reduce noise emitted by any of the components included in the mobile pump system 102 .
- the mobile pump system 102 may include a turbine 108 a , 108 b (a single or multiple turbines may be included) mounted on the trailer 84 and connected to the pump 96 a , 96 b .
- the turbine 108 a , 108 b may be enclosed in a housing.
- the turbine 108 a , 108 b may be an on-board (on the trailer 84 ) turbine to generate power on the trailer 84 for driving the pumps 96 a , 96 b .
- the turbine 108 a , 108 b may be directly coupled to the pump 96 a , 96 b via a gearbox 110 a , 110 b (a single or multiple gearboxes may be included), which may include gear reduction components.
- the turbine 108 a , 108 b may be powered by using field gas (e.g., natural gas) introduced to the turbine to spin the turbine blades to create power to rotate the pump 96 a , 96 b .
- the power generated by the turbine 108 a , 108 b may drive the pump 96 a , 96 b .
- the turbine 108 a , 108 b may be included in the mobile pump system 102 in addition to or in lieu of the electric motor 94 a , 94 b shown in the mobile pump system 82 shown in FIG. 8 .
- a mobile pump system 112 may include all of the components from the mobile pump system 102 of FIG. 9 with the following additions or alterations.
- the mobile pump system 112 may include a fuel tank 114 (or multiple fuel tanks) mounted on the trailer.
- the fuel tank 114 may include any type of fuel suitable to fuel any of the components of the mobile pump system 112 .
- suitable fuels for the fuel tank 114 include compressed natural gas (CNG), liquefied natural gas (LNG), diesel fuel, gasoline, propane, butane, and other suitable hydrocarbons and the like.
- the fuel tank 114 may be in fluid communication with any of the components of the mobile pump system 112 capable of being fueled by the fuel contained in the fuel tank 114 .
- the fuel tank 114 may include any pumps, pipes, hoses, and/or valves required to carry the fuel to the relevant components of the mobile pump system 112 .
- the fuel tank 114 may be used as a backup fuel supply in the event of a fuel supply interruption.
- a fuel supply interruption may include the interruption of field gas (e.g., natural gas supplied directly from the production site at which the mobile pump system 112 is located) to the mobile pump system 112 .
- field gas e.g., natural gas supplied directly from the production site at which the mobile pump system 112 is located
- Inclusion of the fuel tank 114 on the trailer 84 allows the mobile pump system 112 to continue operation even in the event of such a fuel supply interruption, without the deployment of an emergency backup power supply to the production site.
- the mobile pump system 112 may include a conditioning system 116 configured to condition the gas from the fuel tank 114 or the field gas supplied to the mobile pump system 112 .
- the conditioning system 116 may include a gas heater to drop out solids and/or water from the gas and return it to the supply line.
- the conditioning system 116 may include at least one filter to filter out impurities in the fuel that could cause the system to malfunction.
Landscapes
- Engineering & Computer Science (AREA)
- Mechanical Engineering (AREA)
- General Engineering & Computer Science (AREA)
- Life Sciences & Earth Sciences (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Structures Of Non-Positive Displacement Pumps (AREA)
Abstract
Description
- This application claims priority to U.S. Provisional Patent Application No. 62/666,945, filed May 4, 2018, the disclosure of which is hereby incorporated in its entirety by reference.
- The present disclosure relates to a mobile pump system and a method for performing a pressure pumping application.
- Pressure pumping includes a propagation of fractures through layers of rock using pressurized fluid and/or pumping cement into a wellbore to complete it.
- In one non-limiting example of pressure pumping, to extract oil and/or gas trapped in formations beneath the Earth's surface, drilling of a wellbore is required, and the oil and/or gas may be recovered and extracted through the wellbore. Various pumps may be used during the drilling and oil and/or gas recovery process.
- In some non-limiting oilfield applications, drilling may include forming horizontal laterals extending out from a vertical section of the wellbore. The formation defining the vertical or lateral section may be fractured in sections, such that a fracture stimulation treatment is completed in the first section before moving on to apply a fracture stimulation treatment on a second section. This may be performed using a plug-and-perf technique in which a perforating gun is used to initiate fractures in the formation in the section after a plug is positioned between the first section and the second section. The plug seals the first section of the lateral from the other sections. This plug-and-perf technique is repeated for each section of the lateral until all intended sections of the lateral are perforated and fracture stimulated.
- The plug may be positioned at a predetermined location along the lateral by utilizing a pump system to pump a fluid into the wellbore, which exerts a pressure on the plug. The pressure on the plug moves the plug along the lateral to the desired position. Positioning the plug using the pump is considered an ancillary application, commonly referred to as “pumpdown”.
- Existing pumps used in pressure pumping application, such as in ancillary pumpdown applications have numerous drawbacks. For example, existing pumps use an internal combustion engine driven by diesel fuel, which have high carbon footprints. In addition, these existing pumps are cumbersome and require considerable room at the well site. Further, these existing pumps do not allow for sufficiently precise control of flow rate, making it difficult to move the plug to the desired position. Existing pumps are expensive to acquire and maintain, and they create significant noise at a decibel level that is known to harm human hearing without adequate ear protection.
- Further, existing pumping systems utilized in pressure pumping applications, including ancillary pressure pumping applications, are not capable of sufficiently low flow rates or precise control of the flow rate. The existing pump systems lack precise control and the ability to operate at lower flow rates because they utilize conventional transmissions that are incapable of smooth increase or decrease in pumping rates. This may be the result of hesitation and slugging common when primary gears disengage and engage the secondary shaft. As a result, existing pressure pumping systems do not effectively remedy screen outs occurring during hydraulic fracturing applications.
- Therefore, a pump suitable for pressure pumping applications that overcomes some or all of the disadvantages of existing pumps is desired.
- The present disclosure is directed to a mobile pump system including: a trailer movable by a vehicle; and a pump mounted to the trailer, the pump configured to pump a fluid. The pump includes an electrically-driven motor mounted to the trailer or is turbine powered by a turbine mounted to the trailer.
- The pump may be configured to pump the fluid into a wellbore at a tie-in point upstream of a wellhead of the wellbore. The fluid may include water and/or a chemical additive. The pump may include an auger or impeller configured to move the fluid. The pump may not be permanently installed at a site for performing a pressure pumping application. The electrically-driven motor may be fueled by a battery, natural gas, diesel fuel, or gasoline. The pump may be configured to adjust a flow rate of the pump by 1/10th of a bpm. The pump may be in fluid communication with a wellbore. The turbine may be operated using field gas. The mobile pump system may include plurality of pumps mounted to the trailer, where each pump may include an electrically-driven motor mounted to the trailer or may be turbine powered by a turbine mounted on the trailer. The mobile pump system may include controller configured to remotely control the pump. The controller may include a portable computing device. The pump may be configured to pump the fluid at a flow rate as low as 0.1 bpm. The turbine may include a direct coupled gear connection.
- The present disclosure is also directed to a method for performing a pressure pumping application including: providing a mobile pump system including: a trailer movable by a vehicle; and a pump mounted to the trailer, the pump configured to pump a fluid, where the pump includes an electrically-driven motor mounted to the trailer or is turbine powered by a turbine mounted to the trailer.
- The method may include pumping the fluid from a fluid container into a wellbore using the pump to move the fluid from the fluid container into the wellbore. The method may include positioning a plug in a lateral of the wellbore using the fluid pumped into the wellbore. The pump may be configured to pump the fluid into the wellbore at a tie-in point upstream of a wellhead of the wellbore. The fluid may include water and/or a chemical additive. The pump may include an auger or impeller configured to move the fluid. The pump may not be permanently installed at a site for performing a pressure pumping application. The electrically-driven motor may be fueled by a battery, natural gas, diesel fuel, or gasoline. The pump may be configured to adjust a flow rate by 1/10th of a bpm. The pump may be in fluid communication with a wellbore. The turbine may be operated using field gas. The pump may be configured to pump the fluid at a flow rate as low as 0.1 bpm. The pump may be remotely controlled by a controller. The controller may include a portable computing device. The pump may be configured to pump the fluid at a flow rate of up to 140 barrels per minute (bpm) at a pressure of up to 20,000 psi.
- Further embodiments are set forth in the following numbered clauses:
- Clause 1: A mobile pump system comprising: a trailer movable by a vehicle; and a pump mounted to the trailer, the pump configured to pump a fluid, wherein the pump comprises an electrically-driven motor mounted to the trailer or is turbine powered by a turbine mounted to the trailer.
- Clause 2: The mobile pump system of
clause 1, wherein the pump is configured to pump the fluid into a wellbore at a tie-in point upstream of a wellhead of the wellbore. - Clause 3: The mobile pump system of
clause 1 or 2, wherein the fluid comprises water and/or a chemical additive. - Clause 4: The mobile pump system of any of clauses 1-3, wherein the pump comprises an auger or impeller configured to move the fluid.
- Clause 5: The mobile pump system of any of clauses 1-4, wherein the pump is not permanently installed at a site for performing a pressure pumping application.
- Clause 6: The mobile pump system of any of clauses 1-5, wherein the electrically-driven motor is fueled by a battery, natural gas, diesel fuel, or gasoline.
- Clause 7: The mobile pump system of any of clauses 2-6, wherein the pump is configured to adjust a flow rate of the pump by 1/10th of a bpm.
- Clause 8: The mobile pump system of any of clauses 1-7, wherein the pump is in fluid communication with a wellbore.
- Clause 9: The mobile pump system of any of clauses 1-8, wherein the turbine is operated using field gas.
- Clause 10: The mobile pump system of any of clauses 1-9, comprising a plurality of pumps mounted to the trailer, wherein each pump comprises an electrically-driven motor mounted to the trailer or is turbine powered by a turbine mounted on the trailer.
- Clause 11: The mobile pump system of any of clauses 1-10, further comprising a controller configured to remotely control the pump.
- Clause 12: The mobile pump system of
clause 11, wherein the controller comprises a portable computing device. - Clause 13: The mobile pump system of any of clauses 1-12, wherein the pump is configured to pump the fluid at a flow rate as low as 0.1 bpm.
- Clause 14: The mobile pump system of any of clauses 1-13, wherein the turbine comprises a direct coupled gear connection.
- Clause 15: The mobile pump system of any of clauses 1-14, wherein the pump is configured to pump the fluid at a flow rate of up to 140 barrels per minute (bpm) at a pressure of up to 20,000 psi.
- Clause 16: A method for performing a pressure pumping application comprising: providing a mobile pump system comprising: a trailer movable by a vehicle; and a pump mounted to the trailer, the pump configured to pump a fluid, wherein the pump comprises an electrically-driven motor mounted to the trailer or is turbine powered by a turbine mounted to the trailer.
- Clause 17: The method of
clause 16, further comprising: pumping the fluid from a fluid container into a wellbore using the pump to move the fluid from the fluid container into the wellbore. - Clause 18: The method of clause 17, further comprising: positioning a plug in a lateral of the wellbore using the fluid pumped into the wellbore.
- Clause 19: The method of any of clauses 16-18, wherein the pump is configured to pump the fluid into the wellbore at a tie-in point upstream of a wellhead of the wellbore.
- Clause 20: The method of any of clauses 16-19, wherein the fluid comprises water and/or a chemical additive.
- Clause 21: The method of any of clauses 16-20, wherein the pump comprises an auger or impeller configured to move the fluid.
- Clause 22: The method of any of clauses 16-21, wherein the pump is not permanently installed at a site for performing a pressure pumping application.
- Clause 23: The method of any of clauses 16-22, wherein the electrically-driven motor is fueled by a battery, natural gas, diesel fuel, or gasoline.
- Clause 24: The method of any of clauses 16-23, wherein the pump is configured to adjust a flow rate by 1/10th of a bpm.
- Clause 25: The method of any of clauses 16-24, wherein the pump is in fluid communication with a wellbore.
- Clause 26: The method of any of clauses 16-25, wherein the turbine is operated using field gas.
- Clause 27: The method of any of clauses 16-26, wherein the pump is configured to pump the fluid at a flow rate as low as 0.1 bpm.
- Clause 28: The method of any of clauses 16-27, wherein the pump is remotely controlled by a controller.
- Clause 29: The method of
clause 28, wherein the controller comprises a portable computing device. - Clause 30: The method of any of clauses 16-29, wherein the pump is configured to pump the fluid at a flow rate of up to 140 barrels per minute (bpm) at a pressure of up to 20,000 psi.
- Additional advantages and details are explained in greater detail below with reference to the exemplary embodiments that are illustrated in the accompanying schematic figures, in which:
-
FIG. 1 shows a schematic cross-sectional view of the Earth at an oil and/or gas production site utilizing horizontal drilling techniques; -
FIG. 2 shows another schematic cross-sectional view of the Earth at an oil and/or gas production site utilizing horizontal drilling techniques and a mobile pump system; -
FIG. 3 shows a schematic aerial view of a well pad at an oil and/or gas production site, the well pad including a mobile pump system; -
FIG. 4 shows a schematic side view of a mobile pump system according having a trailer and a cab for moving the mobile pump system; -
FIG. 5 shows a schematic top view of a mobile pump system including the trailer and the electrically-driven pump or turbine-driven pump -
FIG. 6 shows a schematic side view of an auger-style pump of a mobile pump system; -
FIG. 7 shows a controller for controlling a mobile pump system; and -
FIG. 8 shows a schematic top view of a mobile pump system including a pump driven by an electric motor; -
FIG. 9 shows a schematic perspective view of a mobile pump system including a pump driven by a turbine; -
FIG. 10 shows a schematic perspective view of a mobile pump system including a pump driven by a turbine, with the trailer including a fuel tank; and -
FIG. 11 shows a schematic top view of a mobile pump system including a secondary pump. - For purposes of the description hereinafter, the terms “end,” “upper,” “lower,” “right,” “left,” “vertical,” “horizontal,” “top,” “bottom,” “lateral,” “longitudinal,” and derivatives thereof shall relate to the invention as it is oriented in the drawing figures. However, it is to be understood that the invention may assume various alternative variations and step sequences, except where expressly specified to the contrary. It is also to be understood that the specific devices and processes illustrated in the attached drawings, and described in the following specification, are simply exemplary embodiments or aspects of the invention. Hence, specific dimensions and other physical characteristics related to the embodiments or aspects disclosed herein are not to be considered as limiting.
- The present disclosure is directed to a mobile pump system that includes: a trailer movable by a vehicle; and a pump mounted to the trailer, the pump configured to pump a fluid, wherein the pump comprises an electrically-driven motor mounted to the trailer or is turbine powered by a turbine mounted to the trailer. The mobile pump system described herein may be suitable for pressure pumping applications.
- Referring to
FIG. 1 , an oil and/orgas production site 10 is shown. At theproduction site 10, the surface 11 (Earth's surface) includeswellbore 12 created by drilling. Thewellbore 12 includes awellhead 13, which is a structural component at thesurface 11 of thewellbore 12 which provides a structural and pressure-containing interface for various drilling and production equipment. Theproduction site 10 may be a site for conducting hydraulic fracturing. - With continued reference to
FIG. 1 , theproduction site 10 may utilize a horizontal drilling technique in which at least one lateral 14 is used. For the horizontal drilling technique, thewellbore 12 may include a vertical region of 2,500 to 25,000, such as 6,000 to 15,000 or 6,000 to 10,000 feet in depth, although the length of this vertical region is not limited to this range. Thewellbore 12 may include a leveling-off point 16 in which the vertical region ends and the lateral 14 is drilled horizontally in the Earth (the lateral 14 may have approximately the same depth from thesurface 11 at all points). Each lateral 14 may have a length of 2,500-25,000, such as 3,000 to 10,000 feet, as measured from the leveling-off point 16 to anend 18 of the lateral 14, although the length of the lateral 14 is not limited to this range. It will be appreciated thatFIG. 1 is not drawn to scale, but merely provides a useful schematic of aproduction site 10 performing horizontal drilling. - The lateral 14 may include a plurality of regions, which are of a predetermined length. Hydraulic fracture stimulation treatment may be performed in the lateral 14 individually at each region. Hydraulic fracture stimulation treatment includes pumping a fracturing fluid into the formation. The lateral 14 of the schematic in
FIG. 1 includes afirst region 20, asecond region 22, athird region 24, afourth region 26, afifth region 28, and asixth region 30. - With continued reference to
FIG. 1 , theproduction site 10 may utilize a “plug-and-perf” method for hydraulic fracture stimulation treatment. InFIG. 1 , hydraulic fracture stimulation treatment has been completed for thefirst region 20. A fracturedfirst region 32 was created in the formation at thefirst region 20. After the hydraulic fracture stimulation treatment was completed in thefirst region 20, afirst plug 34 was positioned at an end of thefirst region 20 closest to the wellhead 13 (a proximal end of the first region 20). Once in place, thisfirst plug 34 may prevent fluid subsequently pumped into the wellbore 12 from entering thefirst region 20. - With continued reference to
FIG. 1 , hydraulic fracture stimulation treatment in thesecond region 22 of the formation may be initiated by lowering a perforating gun 36 (hereinafter “perf gun”) into thewellbore 12 and positioning theperf gun 36 in thesecond region 22. Theperf gun 36 may be lowered into thewellbore 12 using aperf trailer 37. Once positioned correctly, charges of theperf gun 36 may be detonated so as to create multiple connection points from thewellbore 12 to the formation in thesecond region 22. Oil and/or gas may be extracted by escaping from fractures and extracted to thesurface 11 via thewellbore 12. - Referring to
FIG. 2 , theproduction site 10 is shown at a time after that depicted inFIG. 1 . The fracturedsecond region 38 is shown, which was created by theperf gun 36 fromFIG. 1 . It will be appreciated thatFIG. 2 is also not drawn to scale, but merely provides a useful schematic of aproduction site 10 performing horizontal and/or vertical drilling. - In
FIG. 2 , asecond plug 40 is being lowered into thewellbore 12 by aplug trailer 41 to be positioned at a proximal position of the second region 22 (on the end of thesecond region 22 closer to the wellhead 13). Thesecond plug 40 is spaced apart from thefirst plug 34 by approximately the length of thesecond region 22. Thesecond plug 40 may be positioned usingpositioning fluid 42 to provide pressure to thesecond plug 40 to move the second plug along the length of the wellbore 12 (including the lateral 14). The positioningfluid 42 may include water and/or a chemical additive. The chemical additive may include a friction reducer to reduce surface tension. The chemical additive may reduce tension or pipe friction along thewellbore 12 associated with positioning thesecond plug 40. - The
second plug 40 may be positioned using themobile pump system 44 of the present disclosure. Themobile pump system 44 may be used to position thesecond plug 40 as merely one non-limiting example of how themobile pump system 44 may be used in a pressure pumping application. However, it will be appreciated that themobile pump system 44 may be used to complete other pressure pumping applications using the components of themobile pump system 44 described hereinafter. - The
mobile pump system 44 may include atrailer 46 movable by a vehicle (e.g., a cab having a fifth wheel). Thetrailer 46 may be movable by a vehicle, such as a cab, to and from theproduction site 10. In this way, themobile pump system 44 may be conveniently moved from location to location, such as to and from theproduction site 10, and themobile pump system 44 does not need to be permanently installed at theproduction site 10. Thetrailer 46 may be separable/detachable from the vehicle such that thetrailer 46 may be left at theproduction site 10 and the vehicle driven away, or thetrailer 46 may be integrated with the vehicle, such that the vehicle remains at theproduction site 10 while themobile pump system 44 is in use and drives away after use of themobile pump system 44 is completed. - With continued reference to
FIG. 2 , themobile pump system 44 may further include apump 48 mounted to thetrailer 46. Thepump 48 may be configured to pump thepositioning fluid 42 into thewellbore 12. The pump may include anelectric motor 50 mounted to thetrailer 46 or may be powered by aturbine 50 mounted to thetrailer 46. Thetrailer 46 may includemultiple pumps 48 in some embodiments and may include multiple electric motors orturbines 50 for driving thepumps 48. As used herein, the term “electric motor” or “electrically-driven motor” refers to a motor in which electrical energy is converted into mechanical energy. As used herein, the term “turbine” refers to a rotary mechanical device that extracts energy from a fluid (e.g., liquid and/or gas) flow and converts it into useful work to generate electrical energy to power thepump 48. Thetrailer 46 may also include apower generator 52 in connection with thepump 48 to fuel the electrically-driven motor or theturbine 50 of thepump 48. Thepower generator 52 may be battery, natural gas, diesel fuel, or gasoline fueled. Thepump 48 may be driven by the electric motor or theturbine 50 and not by an internal combustion engine. - The
pump 48 may be configured to pump thepositioning fluid 42, or any other fluid, at a flow rate of up to 60 barrels per minute (bpm), such as up to 80 bpm, up to 100 bpm, up to 120 bpm, up to 140 bpm or higher. A barrel is defined as 42 US gallons, which is approximately 159 Liters. Thepump 48 may be configured to pump thepositioning fluid 42 at far lower flow rates, and may pump thepositioning fluid 42 at a flow rate as low as 0.1 bpm (when the pump is not turned off such that it's flow rate would be 0 bpm). Thepump 48 may be controlled such that its flow rate may be controlled within 1/10th of a bpm, resulting in a flow rate within 1/10th of a bpm compared to a predetermined flow rate. The pump may be configured to adjust the flow rate by 1/10th of a bpm (e.g., adjust the flow rate of thepump 48 from 60.0 bpm to 59.9 bpm or from 0.2 bpm to 0.1 bpm). Existing pressure pumping systems, including ancillary pressure pumping applications, are not capable of such low flow rates or such precise control of the flow rate. The existing pump systems lack precise control and the ability to operate at lower flow rates because they utilize conventional transmissions that are incapable of smooth increase or decrease in pumping rates. This may be the result of hesitation and slugging common when primary gears disengage and engage the secondary shaft. - The ability to pump at lower rates and to more precisely control the flow rate of the
pump 48 may be especially useful in post-occurrence remedying of “screen outs,” which are common in hydraulic fracturing applications. A screen out occurs when proppant and fluid (of the positioningfluid 42, for example) can no longer be injected into the formation. This may be due to resistant stresses of the formation becoming too excessive or surface-originated reasons resulting in loss of viscosity to carry proppant so that it falls out of suspension and plugs perforations in thewellbore 12. In this way, thewellbore 12 becomes “packed” with proppant, which does not allow any further operations to continue due to high pressures that cannot be overcome from these blockages. - In response to screen outs, the
wellbore 12 may be opened at thesurface 11 to relieve pressure and to carry at least some of the proppant out of thewellbore 12 and create a pathway to continue fluid injection to clear thewellbore 12 and allow operations to continue, which is a dangerous operation. An attempt to continue pumping operations at low rates to avoid reaching maximum pressure so that the proppant that is packed is forced through perforations and into thewellbore 12 may be attempted. However, due to the limitations of existing pumps with conventional engines and transmissions, the pump cannot pump at low enough rates to avoid again reaching maximum pressure. As a result, existing systems are often required to switch to a coiled tubing procedure to wash the proppant out and carry it back to the surface so that thewellbore 12 is finally clear. The coiled tubing procedure results in shutdown of operations for 3-4 days and is additionally expensive to complete. - In contrast, existing systems are able to overcome these screen outs successfully without reverting to the coiled tubing procedure because the electric motor or the
turbine 50 of thepump 48 allows thepump 48 to inject fluid for displacement at lower rates (as low as 0.1 bpm) over the course of hours or days without the risks posed by existing systems. - The ability to pump fluids at lower rates and to more precisely control the flow rate of the
pump 48 may be especially useful in prevention or mitigation of the adiabatic effect which can cause wireline cable melting and/or failure during pump down operations, which are common in hydraulic fracturing applications. On pump downs and related jobs involving wireline operations with pump assist, the wellhead is equipped with a lubricator and flow tubes to enable operations in a wellbore that can have pressure of several thousand pounds or more of pressure. The process of bringing the lubricator and the wellbore to the same pressure is known as “equalization.” When the air in the lubricator compresses faster than it can be evacuated, the adiabatic compression can cause the temperature to rise to as much as 1,200° F. (−650° C.). At high temperatures, the insulating material of the cable would melt and the metallurgy of the steel in the cable would change, causing the actual wire in the wireline to become brittle and break, even to the point of severing the wireline within the lubricator. A common name for this condition is “wireline burn up” though other colloquialisms and phrases (such as “E-line burn”) describe the same condition. - In practice, to avoid wireline burn-up, the lubricator may first be filled with fluid prior to equalizing; this practice can mitigate much of the air and therefore most of the energy to cause damage. In order to fill the lubricator with fluid without inducing wireline burn-up, the fluid must be introduced at very low rates so that the air can be evacuated at an equivalent rate so as not to introduce temperature increases caused by compressing air rapidly. However, due to the limitations of existing pump systems with conventional engines and transmissions, the pump cannot pump at low enough rates to completely avoid against reaching damaging high temperatures. In contrast, the
pump 48 would be able to overcome this situation successfully because the electric motor or theturbine 50 of thepump 48 allows thepump 48 to inject fluid for displacement of the air in the lubricator at lower rates (as low as approximately 0.1 bpm) without the risks posed by existing systems. - The
pump 48 may be configured to pump fluid at a pressure of up to 20,000 psi, such as up to 15,000 psi, up to 12,000 psi, up to 10,000 psi, up to 8,000 psi, or up to 6,000 psi, although higher pressures are also contemplated. - With continued reference to
FIG. 2 , afluid tank 54 containing the positioningfluid 42 may be in fluid communication with thepump 48. Thepump 48 may pump thepositioning fluid 42 from thefluid tank 54 into thewellbore 12 to position thesecond plug 40 at a predetermined position in thewellbore 12. - With continued reference to
FIG. 2 , themobile pump system 44 may position thesecond plug 40 at a predetermined position in thewellbore 12. Thesecond plug 40 may be positioned in the wellbore by providing the previously-describedmobile pump system 44. Thepump 48 of themobile pump system 44 may be placed in fluid communication with thewellbore 12. The positioningfluid 42 may be pumped from thefluid tank 54 into thewellbore 12 using thepump 48. The positioningfluid 42 pumped into thewellbore 12 may exert a pressure on thesecond plug 40 so as to move thesecond plug 40 along the lateral 14 and into the predetermined position. The position of thesecond plug 40 may be monitored from the surface by any means known in the art. The flow rate of the positioningfluid 42 pumped by thepump 48 may be adjusted and controlled to position thesecond plug 40. The flow rate may be increased or decreased to adjust the rate at which thesecond plug 40 is moved. For example, when thesecond plug 40 is proximate the predetermined position, the flow rate of positioningfluid 42 may be lowered so that the position of thesecond plug 40 can be more precisely selected. - The
mobile pump system 44 described herein may be used for any pressure pumping in which its characteristics are suitable and is not limited to the above-described application. For example, themobile pump system 44 may be used in hydraulic fracturing applications. Hydraulic fracturing applications include any application associated with hydraulic fracturing performed at a production site. Hydraulic fracturing refers to fluid injected down the wellbore through perforations exceeding the minimum fracture pressure needed to fracture the rock in the formation. An example of a hydraulic fracturing application includes ancillary applications (“pumpdown”), such as positioning a plug (previously described), drillout applications, injecting acid into the formation, pressure testing casing, injecting diverter materials, “toe preps” involving initiating the first fracture network in a well, and the like. Drillout applications may include applications performed after the drilling and fracturing process has concluded and the well is being prepared to deliver hydrocarbon production. As one example, a drillout application may include milling or drilling out plugs previously positioned in the laterals and removing debris from the milled plugs by pumping the debris from the plug location to the surface. - The
mobile pump system 44 allows for the reduction of capital costs compared to existing pump systems as themobile pump system 44 requires less capital costs to build and operate. Themobile pump system 44 also significantly reduces repair and maintenance costs compared to existing systems. The use of the electric motor orturbine 50 to drive thepump 48 helps to reduce repair and maintenance costs. The electric motor orturbine 50 has a higher run time before requiring repairs compared to conventional internal combustion engines (motors) used in existing pumps, which are diesel driven, for example. Keeping the electric motor orturbine 50 cool and lubricated allows the electric motor orturbine 50 to have a longer running life compared to the motors used in existing systems. The electric motor orturbine 50 also run more efficiently compared to the motors used in existing systems, such as in terms of emissions and consumption of fuel. - The
mobile pump system 44 using the electric motor orturbine 50 to drive thepump 48 also requires significantly less fuel compared to existing systems. The electric motor orturbine 50 may utilize natural gas powered electric generation, such as the field gas available at a production site. Thus, sulfur and other pollutants that arise from diesel combustion in conventional internal combustion motors are not present in the combustion of natural gas powered electric generation. The inclusion of the electric motor or theturbine 50 in themobile pump system 44 also reduces the noise associated with themobile pump system 44 as pumps used in existing systems provide significant noise pollution and make it difficult to operate such pumps in residential areas (e.g., near housing plans, schools, hospitals, and the like). - The
mobile pump system 44 includes a more compact design of thepumps 48 compared with existing systems. Multiple pumps 48 may be included on thetrailer 46. The more compact system contributes to asafe production site 10 as there are less components at theproduction site 10 to cause a navigational and/or tripping hazard. This compact design also allows for themobile pump system 44 to be set-up faster, resulting in less wasted time and faster time to production. Moreover, themobile pump system 44 may include multiple of at least on component included in the system, such asmultiple pumps 48, multiple electric motors orturbines 50,multiple controllers 80, and the like. The redundancy associated with certain of the components mounted on thetrailer 46 of themobile pump system 44 allows the system to avoid stopping operation of the pressure pumping application should one of the redundant components fail. - Referring to
FIG. 3 , an aerial view of theproduction site 10 is shown. Theproduction site 10 includes awell pad 56. Thewell pad 56 includes sixwellbores 12A-12F, each wellbore having a vertical region and at least one lateral traversing a direction different from the other wellbores of thewell pad 56. In the schematic inFIG. 3 , the non-limiting example of a pressure pumping application is being conducted at only thefirst wellbore 12A; however, multiple well heads may be in production (e.g., conducting oilfield activity) simultaneously. - The
production site 10 may include at least onefracturing trailer 58A-58F, each including at least one fracturing pump 60A-60F. Theproduction site 10 may further include sand and fracturing fluid storage tanks 62, which include sand and fracturing fluid used to keep fractures in the formation open. Theproduction site 10 may further include a water tank 64 for pumping water into thefirst wellbore 12A. The water tank 64 may be in addition to or the same as thefluid tank 54 containing the positioningfluid 42. Theproduction site 10 may further include achemical storage tank 66, which may store any useful chemical, such as a friction reducer (e.g., polyacrylamide or a guar-based chemical). The fracturing pumps 60A-60F may be in fluid communication with at least one of the sand and fracturing fluid storage tanks 62, the water tank 64, and thechemical storage tank 66 to pump the various materials and/or fluids contained therein into thefirst wellbore 12A via piping 70. The piping 70 may include anisolation valve 72 for isolating the fracturing pumps 60A-60F from thefirst wellbore 12A when the fracturing pumps 60A-60F are not pumping fluid/material into thefirst wellbore 12A. - With continued reference to
FIG. 3 , theproduction site 10 may further include adata monitoring station 68, which may be used to monitor all operations conducted at theproduction site 10 and control those operations accordingly. In some non-limiting examples, thedata monitoring station 68 may be remote from theproduction site 10. - With continued reference to
FIG. 3 ,production site 10 may further include themobile pump system 44A. The production site may include a singlemobile pump system 44A or multiplemobile pump systems 44A-44B, as necessary. In the non-limiting example ofFIG. 3 , a firstmobile pumping system 44A is used to pump positioningfluid 42 into thefirst wellbore 12A. The firstmobile pumping system 44A may include afirst trailer 46A, afirst power generator 52A, and afirst pump 48A having a firstelectric motor 50A. Theproduction site 10 may utilize a secondmobile pumping system 44B in addition to or in lieu of the firstmobile pumping system 44A. The secondmobile pumping system 44B may include asecond trailer 46B, asecond power generator 52B, and twopumps electric motor production site 10 may include thefluid tank 54 containing the positioningfluid 42, and thefluid tank 54 may be in fluid communication with thefirst pump 48A of the firstmobile pumping system 44A. The firstmobile pumping system 44A and the secondmobile pumping system 44B may be moved to and from theproduction site 10 without being permanently installed at thepumping site 10. - With continued reference to
FIG. 3 , thefirst pump 48A may be in fluid communication with thefirst wellbore 12A so as to pump thepositioning fluid 42 into thefirst wellbore 12A. Thefirst pump 48A may be in fluid communication with the piping 70 so as to be in fluid communication with thefirst wellbore 12A, and thefirst pump 48A may intersect with the piping 70 at a tie-in point 74. The tie-in point 74 may be upstream of the wellhead of thefirst wellbore 12A (e.g., before the piping 70 reaches the wellhead of thefirst wellbore 12A). - Referring to
FIG. 4 , a non-limiting example of themobile pump system 44 may include acab 76. Thecab 76 may be a truck capable of attaching thetrailer 46 thereto (such as via a fifth wheel), so that thetrailer 46 may be hauled to and from theproduction site 10. Thetrailer 46 may be detachable from thecab 76 so that it may be left at the job site, or thetrailer 46 may be an integrated part of the cab 76 (not detachable therefrom). In some examples, thecab 76 is thepower generator 52 because the cab may fuel the electric motor orturbine 50 used to drive thepump 48. - Referring to
FIG. 5 , a top view of a non-limiting example of themobile pump system 44 is shown, with themobile pump system 44 including thetrailer 46, thepump 48 having theelectric motor 50, and thepower generator 52. Thepower generator 52 may be connected to the pump 48 (e.g., the electric motor 50) to fuel theelectric motor 50, such that theelectric motor 50 may drive thepump 48. - Referring to
FIG. 6 , a non-limiting example of thepump 48 is shown. Thepump 48 may be any pump suitable for pumping the positioningfluid 42 as previously described. In one example, thepump 48 may be an auger-style pump that includes an auger orimpeller 78 driven by the electric motor or theturbine 50 to move thepositioning fluid 42 into thewellbore 12. The auger-style pump may provide certain advantages, including allowing for a more precise control of flow rate, reduced maintenance, and ease of maintenance (based on the reduced number and simplicity of components). - Referring to
FIG. 7 , thepump 48, the electric motor or theturbine 50, thegenerator 52, and/or other components (“controllable components”) of themobile pump system 44 may be controlled remotely by acontroller 80. As used herein, “remotely” refers to a geographic location separate from the controllable component. Thepump 48 may be controlled from thedata monitoring station 68 or other location at the production site 10 (shown inFIG. 3 ), or thepump 48 may be controlled off-site (not at the production site 10). Thepump 48 may be controlled by thecontroller 80 that is a portable computing device, such that the portable computing device may be moved between locations and is still able to control thepump 48. The portable computing device may be, for instance, a laptop computer, a tablet computer, or a smartphone. Thus, relevant data associated with themobile pump system 44 may be communicated to thecontroller 80 remote from the controllable component(s). - An exemplary graphical user interface (GUI) displayed on the
controller 80 is shown inFIG. 7 , and a user may control the controllable components by interacting with the GUI on thecontroller 80. The GUI may allow the user to control various features of the controllable components. Non-limiting examples include controlling the pump's 48 flow rate or the pressure of thepump 48. The GUI may display the flow rate and pressure of thepump 48. The GUI may allow the user to turn thepump 48 on or off. The GUI may display the fill level of thefluid tank 54 or provide a status of the electric motor or theturbine 50, such as whether any issues are identified with the electric motor or the turbine. It will be appreciated that other aspects of themobile pump system 44 may be controlled by interacting with the GUI, and any suitable layout of the GUI may be used. Multiple controllable components (e.g., multiple pumps) may be controllable from thesame controller 80. - Beyond providing the capability to adjust certain parameters of the system, the GUI may display on the controller various diagnostic and monitoring information. As non-limiting examples, the GUI may display electric motor or the turbine temperature, fluid levels, and pump revolutions per minute.
- Referring to
FIG. 8 , amobile pump system 82. Themobile pump system 82 may include atrailer 84 attachable to a vehicle for moving thetrailer 84 to various locations. Themobile pump system 82 may include acontroller 86 mounted on thetrailer 84, thecontroller 86 in electrical communication with other components of the mobile pump system 82 (e.g., anelectrical transformer 88, avariable frequency drive 90, a heat exchanger, an electric motor 94, a pump 96, asecondary pump 98, and a secondary electric motor 100). Thecontroller 86 may communicate control signals to the other components to cause the other components to perform a predetermined action (e.g., activating or deactivating a component, changing a pump rate, changing a heat exchanger temperature, and the like). - The
mobile pump system 82 may include anelectrical transformer 88 mounted on thetrailer 84. Theelectrical transformer 88 may increase or decrease a voltage from an external power source for use by one of the components of themobile pump system 82. This may allow components of themobile pump system 82 to be powered by an external power source not included on thetrailer 84 by electrically connecting the external power source to thetransformer 88, which may be electrically connected to the other components. - The
mobile pump system 82 may include the variable frequency drive 90 mounted on thetrailer 84. Thevariable frequency drive 90 may include an electro-mechanical drive system to control motor speed and/or torque of the electric motor 94 by varying motor input frequency and/or voltage. - The
mobile pump system 82 may include theheat exchanger 92 mounted on thetrailer 84 to regulate temperature of at least one of the other components (e.g., the electric motor 94 and/or the pump 96), such that the component can operate more efficiently. Theheat exchanger 92 may function as a cooler to prevent a component of themobile pump system 82 from overheating. - The
mobile pump system 82 may include the electric motor 94 mounted on thetrailer 84, the electric motor 94 as previously described herein. Themobile pump system 82 may also include thepump trailer 84. Thepump pump 48. Thepump - With continued reference to
FIG. 8 and referring toFIG. 11 , themobile pump system 82 may include asecondary pump 98 and/or a secondary motor 100 (e.g., an electric motor) mounted on thetrailer 84. Thesecondary pump 98 may include a triplex pump. Thesecondary pump 98 may be configured for pumping fluid at higher pressure compared to thepump mobile pump system 82. Thesecondary pump 98 may be selectively activated in situations in which themobile pump system 82 is required to operate at a higher pressure. Thesecondary pump 98 may be isolated from thepump secondary motor 100 may drive thesecondary pump 98. Thepump secondary pump 98 may be in fluid communication with the wellbore 12 (seeFIG. 2 ). - Referring to
FIG. 9 , amobile pump system 102 may include any of the components discussed in connection with themobile pump system 82 fromFIG. 8 and may include any additional or alternative components as hereinafter described. Thetrailer 84 may include aconnection portion 104 configured to engage with an engagement portion of a cab (e.g., a fifth wheel). Theconnection portion 104 may engage with a cab, such that themobile pump system 102 may be transported by the cab to various locations, such as to and from a production site. - The
mobile pump system 102 may include aninlet filter silencer 106 mounted on thetrailer 84 to reduce noise emitted by any of the components included in themobile pump system 102. - The
mobile pump system 102 may include aturbine trailer 84 and connected to thepump turbine turbine trailer 84 for driving thepumps turbine pump gearbox turbine pump turbine pump turbine mobile pump system 102 in addition to or in lieu of theelectric motor mobile pump system 82 shown inFIG. 8 . - Referring to
FIG. 10 , a mobile pump system 112 may include all of the components from themobile pump system 102 ofFIG. 9 with the following additions or alterations. The mobile pump system 112 may include a fuel tank 114 (or multiple fuel tanks) mounted on the trailer. Thefuel tank 114 may include any type of fuel suitable to fuel any of the components of the mobile pump system 112. Non-limiting examples of suitable fuels for thefuel tank 114 include compressed natural gas (CNG), liquefied natural gas (LNG), diesel fuel, gasoline, propane, butane, and other suitable hydrocarbons and the like. Thefuel tank 114 may be in fluid communication with any of the components of the mobile pump system 112 capable of being fueled by the fuel contained in thefuel tank 114. Thefuel tank 114 may include any pumps, pipes, hoses, and/or valves required to carry the fuel to the relevant components of the mobile pump system 112. - The
fuel tank 114 may be used as a backup fuel supply in the event of a fuel supply interruption. A fuel supply interruption may include the interruption of field gas (e.g., natural gas supplied directly from the production site at which the mobile pump system 112 is located) to the mobile pump system 112. Inclusion of thefuel tank 114 on thetrailer 84 allows the mobile pump system 112 to continue operation even in the event of such a fuel supply interruption, without the deployment of an emergency backup power supply to the production site. - The mobile pump system 112 may include a
conditioning system 116 configured to condition the gas from thefuel tank 114 or the field gas supplied to the mobile pump system 112. Theconditioning system 116 may include a gas heater to drop out solids and/or water from the gas and return it to the supply line. Theconditioning system 116 may include at least one filter to filter out impurities in the fuel that could cause the system to malfunction. - Although the invention has been described in detail for the purpose of illustration based on what is currently considered to be the most practical and preferred embodiments, it is to be understood that such detail is solely for that purpose and that the invention is not limited to the disclosed embodiments, but, on the contrary, is intended to cover modifications and equivalent arrangements that are within the spirit and scope of the appended claims. For example, it is to be understood that the present invention contemplates that, to the extent possible, one or more features of any embodiment can be combined with one or more features of any other embodiment.
Claims (20)
Priority Applications (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US16/401,464 US20190338762A1 (en) | 2018-05-04 | 2019-05-02 | Mobile Pump System |
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US201862666945P | 2018-05-04 | 2018-05-04 | |
US16/401,464 US20190338762A1 (en) | 2018-05-04 | 2019-05-02 | Mobile Pump System |
Publications (1)
Publication Number | Publication Date |
---|---|
US20190338762A1 true US20190338762A1 (en) | 2019-11-07 |
Family
ID=68384668
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US16/401,464 Abandoned US20190338762A1 (en) | 2018-05-04 | 2019-05-02 | Mobile Pump System |
Country Status (2)
Country | Link |
---|---|
US (1) | US20190338762A1 (en) |
CA (1) | CA3042189C (en) |
Cited By (44)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US10954770B1 (en) | 2020-06-09 | 2021-03-23 | Bj Energy Solutions, Llc | Systems and methods for exchanging fracturing components of a hydraulic fracturing unit |
US10961908B1 (en) | 2020-06-05 | 2021-03-30 | Bj Energy Solutions, Llc | Systems and methods to enhance intake air flow to a gas turbine engine of a hydraulic fracturing unit |
US10961912B1 (en) | 2019-09-13 | 2021-03-30 | Bj Energy Solutions, Llc | Direct drive unit removal system and associated methods |
US10961914B1 (en) | 2019-09-13 | 2021-03-30 | BJ Energy Solutions, LLC Houston | Turbine engine exhaust duct system and methods for noise dampening and attenuation |
US10968837B1 (en) | 2020-05-14 | 2021-04-06 | Bj Energy Solutions, Llc | Systems and methods utilizing turbine compressor discharge for hydrostatic manifold purge |
US10989180B2 (en) | 2019-09-13 | 2021-04-27 | Bj Energy Solutions, Llc | Power sources and transmission networks for auxiliary equipment onboard hydraulic fracturing units and associated methods |
US11002189B2 (en) | 2019-09-13 | 2021-05-11 | Bj Energy Solutions, Llc | Mobile gas turbine inlet air conditioning system and associated methods |
US11015594B2 (en) | 2019-09-13 | 2021-05-25 | Bj Energy Solutions, Llc | Systems and method for use of single mass flywheel alongside torsional vibration damper assembly for single acting reciprocating pump |
US11015536B2 (en) | 2019-09-13 | 2021-05-25 | Bj Energy Solutions, Llc | Methods and systems for supplying fuel to gas turbine engines |
US11022526B1 (en) | 2020-06-09 | 2021-06-01 | Bj Energy Solutions, Llc | Systems and methods for monitoring a condition of a fracturing component section of a hydraulic fracturing unit |
US11028677B1 (en) | 2020-06-22 | 2021-06-08 | Bj Energy Solutions, Llc | Stage profiles for operations of hydraulic systems and associated methods |
US11066915B1 (en) | 2020-06-09 | 2021-07-20 | Bj Energy Solutions, Llc | Methods for detection and mitigation of well screen out |
US11109508B1 (en) | 2020-06-05 | 2021-08-31 | Bj Energy Solutions, Llc | Enclosure assembly for enhanced cooling of direct drive unit and related methods |
US11111768B1 (en) | 2020-06-09 | 2021-09-07 | Bj Energy Solutions, Llc | Drive equipment and methods for mobile fracturing transportation platforms |
US20210285432A1 (en) * | 2020-03-12 | 2021-09-16 | American Jereh International Corporation | Continous high-power turbine fracturing equipment |
US11125066B1 (en) | 2020-06-22 | 2021-09-21 | Bj Energy Solutions, Llc | Systems and methods to operate a dual-shaft gas turbine engine for hydraulic fracturing |
US11149533B1 (en) | 2020-06-24 | 2021-10-19 | Bj Energy Solutions, Llc | Systems to monitor, detect, and/or intervene relative to cavitation and pulsation events during a hydraulic fracturing operation |
US11193361B1 (en) | 2020-07-17 | 2021-12-07 | Bj Energy Solutions, Llc | Methods, systems, and devices to enhance fracturing fluid delivery to subsurface formations during high-pressure fracturing operations |
US11208880B2 (en) | 2020-05-28 | 2021-12-28 | Bj Energy Solutions, Llc | Bi-fuel reciprocating engine to power direct drive turbine fracturing pumps onboard auxiliary systems and related methods |
US11208953B1 (en) | 2020-06-05 | 2021-12-28 | Bj Energy Solutions, Llc | Systems and methods to enhance intake air flow to a gas turbine engine of a hydraulic fracturing unit |
US11220895B1 (en) | 2020-06-24 | 2022-01-11 | Bj Energy Solutions, Llc | Automated diagnostics of electronic instrumentation in a system for fracturing a well and associated methods |
US11236739B2 (en) | 2019-09-13 | 2022-02-01 | Bj Energy Solutions, Llc | Power sources and transmission networks for auxiliary equipment onboard hydraulic fracturing units and associated methods |
US11268346B2 (en) | 2019-09-13 | 2022-03-08 | Bj Energy Solutions, Llc | Fuel, communications, and power connection systems |
US20220120262A1 (en) * | 2020-03-12 | 2022-04-21 | American Jereh International Corporation | Continuous high-power turbine fracturing equipment |
US11408794B2 (en) | 2019-09-13 | 2022-08-09 | Bj Energy Solutions, Llc | Fuel, communications, and power connection systems and related methods |
US11415125B2 (en) | 2020-06-23 | 2022-08-16 | Bj Energy Solutions, Llc | Systems for utilization of a hydraulic fracturing unit profile to operate hydraulic fracturing units |
US11428165B2 (en) | 2020-05-15 | 2022-08-30 | Bj Energy Solutions, Llc | Onboard heater of auxiliary systems using exhaust gases and associated methods |
US11459863B2 (en) * | 2019-10-03 | 2022-10-04 | U.S. Well Services, LLC | Electric powered hydraulic fracturing pump system with single electric powered multi-plunger fracturing pump |
US11473413B2 (en) | 2020-06-23 | 2022-10-18 | Bj Energy Solutions, Llc | Systems and methods to autonomously operate hydraulic fracturing units |
US11519395B2 (en) | 2019-09-20 | 2022-12-06 | Yantai Jereh Petroleum Equipment & Technologies Co., Ltd. | Turbine-driven fracturing system on semi-trailer |
US11560845B2 (en) | 2019-05-15 | 2023-01-24 | Bj Energy Solutions, Llc | Mobile gas turbine inlet air conditioning system and associated methods |
US11608726B2 (en) | 2021-01-11 | 2023-03-21 | Yantai Jereh Petroleum Equipment & Technologies Co., Ltd. | Switchable apparatus, well site and control method thereof, device, and storage medium |
US11608725B2 (en) | 2019-09-13 | 2023-03-21 | Bj Energy Solutions, Llc | Methods and systems for operating a fleet of pumps |
US20230088221A1 (en) * | 2019-09-13 | 2023-03-23 | Bj Energy Solutions, Llc | Fuel, communications, and power connection systems and related methods |
US20230103589A1 (en) * | 2017-12-05 | 2023-04-06 | U.S. Well Services, LLC | High horsepower pumping configuration for an electric hydraulic fracturing system |
US11624326B2 (en) | 2017-05-21 | 2023-04-11 | Bj Energy Solutions, Llc | Methods and systems for supplying fuel to gas turbine engines |
US11635074B2 (en) | 2020-05-12 | 2023-04-25 | Bj Energy Solutions, Llc | Cover for fluid systems and related methods |
US11639654B2 (en) | 2021-05-24 | 2023-05-02 | Bj Energy Solutions, Llc | Hydraulic fracturing pumps to enhance flow of fracturing fluid into wellheads and related methods |
US20230151723A1 (en) * | 2021-11-18 | 2023-05-18 | Yantai Jereh Petroleum Equipment & Technologies Co., Ltd. | Turbine Fracturing Apparatus and Turbine Fracturing Well Site |
US11702919B2 (en) | 2019-09-20 | 2023-07-18 | Yantai Jereh Petroleum Equipment & Technologies Co., Ltd. | Adaptive mobile power generation system |
US11788519B2 (en) | 2019-09-20 | 2023-10-17 | Yantai Jereh Petroleum Equipment & Technologies Co., Ltd. | Turbine fracturing equipment |
US11867118B2 (en) | 2019-09-13 | 2024-01-09 | Bj Energy Solutions, Llc | Methods and systems for supplying fuel to gas turbine engines |
US11933153B2 (en) | 2020-06-22 | 2024-03-19 | Bj Energy Solutions, Llc | Systems and methods to operate hydraulic fracturing units using automatic flow rate and/or pressure control |
US11939853B2 (en) | 2020-06-22 | 2024-03-26 | Bj Energy Solutions, Llc | Systems and methods providing a configurable staged rate increase function to operate hydraulic fracturing units |
Citations (4)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20030164252A1 (en) * | 2002-02-26 | 2003-09-04 | Rae Philip J. | Chemically enhanced drilling methods |
US20080029267A1 (en) * | 2006-06-02 | 2008-02-07 | Rod Shampine | Horizontal oilfield pumping systems |
US20180320503A1 (en) * | 2015-12-16 | 2018-11-08 | Halliburton Energy Services, Inc. | Bridge Plug Sensor for Bottom-Hole Measurements |
US20200088202A1 (en) * | 2018-04-27 | 2020-03-19 | Axel Michael Sigmar | Integrated MVDC Electric Hydraulic Fracturing Systems and Methods for Control and Machine Health Management |
-
2019
- 2019-05-02 US US16/401,464 patent/US20190338762A1/en not_active Abandoned
- 2019-05-03 CA CA3042189A patent/CA3042189C/en active Active
Patent Citations (4)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20030164252A1 (en) * | 2002-02-26 | 2003-09-04 | Rae Philip J. | Chemically enhanced drilling methods |
US20080029267A1 (en) * | 2006-06-02 | 2008-02-07 | Rod Shampine | Horizontal oilfield pumping systems |
US20180320503A1 (en) * | 2015-12-16 | 2018-11-08 | Halliburton Energy Services, Inc. | Bridge Plug Sensor for Bottom-Hole Measurements |
US20200088202A1 (en) * | 2018-04-27 | 2020-03-19 | Axel Michael Sigmar | Integrated MVDC Electric Hydraulic Fracturing Systems and Methods for Control and Machine Health Management |
Cited By (154)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US11624326B2 (en) | 2017-05-21 | 2023-04-11 | Bj Energy Solutions, Llc | Methods and systems for supplying fuel to gas turbine engines |
US20230103589A1 (en) * | 2017-12-05 | 2023-04-06 | U.S. Well Services, LLC | High horsepower pumping configuration for an electric hydraulic fracturing system |
US11560845B2 (en) | 2019-05-15 | 2023-01-24 | Bj Energy Solutions, Llc | Mobile gas turbine inlet air conditioning system and associated methods |
US11655763B1 (en) | 2019-09-13 | 2023-05-23 | Bj Energy Solutions, Llc | Direct drive unit removal system and associated methods |
US11408794B2 (en) | 2019-09-13 | 2022-08-09 | Bj Energy Solutions, Llc | Fuel, communications, and power connection systems and related methods |
US10982596B1 (en) | 2019-09-13 | 2021-04-20 | Bj Energy Solutions, Llc | Direct drive unit removal system and associated methods |
US10989180B2 (en) | 2019-09-13 | 2021-04-27 | Bj Energy Solutions, Llc | Power sources and transmission networks for auxiliary equipment onboard hydraulic fracturing units and associated methods |
US11002189B2 (en) | 2019-09-13 | 2021-05-11 | Bj Energy Solutions, Llc | Mobile gas turbine inlet air conditioning system and associated methods |
US11015594B2 (en) | 2019-09-13 | 2021-05-25 | Bj Energy Solutions, Llc | Systems and method for use of single mass flywheel alongside torsional vibration damper assembly for single acting reciprocating pump |
US11971028B2 (en) | 2019-09-13 | 2024-04-30 | Bj Energy Solutions, Llc | Systems and method for use of single mass flywheel alongside torsional vibration damper assembly for single acting reciprocating pump |
US11015536B2 (en) | 2019-09-13 | 2021-05-25 | Bj Energy Solutions, Llc | Methods and systems for supplying fuel to gas turbine engines |
US11530602B2 (en) | 2019-09-13 | 2022-12-20 | Bj Energy Solutions, Llc | Power sources and transmission networks for auxiliary equipment onboard hydraulic fracturing units and associated methods |
US11725583B2 (en) | 2019-09-13 | 2023-08-15 | Bj Energy Solutions, Llc | Mobile gas turbine inlet air conditioning system and associated methods |
US11060455B1 (en) | 2019-09-13 | 2021-07-13 | Bj Energy Solutions, Llc | Mobile gas turbine inlet air conditioning system and associated methods |
US11512642B1 (en) | 2019-09-13 | 2022-11-29 | Bj Energy Solutions, Llc | Direct drive unit removal system and associated methods |
US10961912B1 (en) | 2019-09-13 | 2021-03-30 | Bj Energy Solutions, Llc | Direct drive unit removal system and associated methods |
US11092152B2 (en) | 2019-09-13 | 2021-08-17 | Bj Energy Solutions, Llc | Systems and method for use of single mass flywheel alongside torsional vibration damper assembly for single acting reciprocating pump |
US11098651B1 (en) | 2019-09-13 | 2021-08-24 | Bj Energy Solutions, Llc | Turbine engine exhaust duct system and methods for noise dampening and attenuation |
US11598263B2 (en) | 2019-09-13 | 2023-03-07 | Bj Energy Solutions, Llc | Mobile gas turbine inlet air conditioning system and associated methods |
US10961914B1 (en) | 2019-09-13 | 2021-03-30 | BJ Energy Solutions, LLC Houston | Turbine engine exhaust duct system and methods for noise dampening and attenuation |
US11473503B1 (en) | 2019-09-13 | 2022-10-18 | Bj Energy Solutions, Llc | Direct drive unit removal system and associated methods |
US11604113B2 (en) | 2019-09-13 | 2023-03-14 | Bj Energy Solutions, Llc | Fuel, communications, and power connection systems and related methods |
US11608725B2 (en) | 2019-09-13 | 2023-03-21 | Bj Energy Solutions, Llc | Methods and systems for operating a fleet of pumps |
US11473997B2 (en) | 2019-09-13 | 2022-10-18 | Bj Energy Solutions, Llc | Fuel, communications, and power connection systems and related methods |
US11149726B1 (en) | 2019-09-13 | 2021-10-19 | Bj Energy Solutions, Llc | Systems and method for use of single mass flywheel alongside torsional vibration damper assembly for single acting reciprocating pump |
US11156159B1 (en) | 2019-09-13 | 2021-10-26 | Bj Energy Solutions, Llc | Mobile gas turbine inlet air conditioning system and associated methods |
US11867118B2 (en) | 2019-09-13 | 2024-01-09 | Bj Energy Solutions, Llc | Methods and systems for supplying fuel to gas turbine engines |
US11859482B2 (en) | 2019-09-13 | 2024-01-02 | Bj Energy Solutions, Llc | Power sources and transmission networks for auxiliary equipment onboard hydraulic fracturing units and associated methods |
US11852001B2 (en) | 2019-09-13 | 2023-12-26 | Bj Energy Solutions, Llc | Methods and systems for operating a fleet of pumps |
US11629584B2 (en) | 2019-09-13 | 2023-04-18 | Bj Energy Solutions, Llc | Power sources and transmission networks for auxiliary equipment onboard hydraulic fracturing units and associated methods |
US11280331B2 (en) | 2019-09-13 | 2022-03-22 | Bj Energy Solutions, Llc | Systems and method for use of single mass flywheel alongside torsional vibration damper assembly for single acting reciprocating pump |
US11578660B1 (en) | 2019-09-13 | 2023-02-14 | Bj Energy Solutions, Llc | Direct drive unit removal system and associated methods |
US11459954B2 (en) | 2019-09-13 | 2022-10-04 | Bj Energy Solutions, Llc | Turbine engine exhaust duct system and methods for noise dampening and attenuation |
US11460368B2 (en) | 2019-09-13 | 2022-10-04 | Bj Energy Solutions, Llc | Fuel, communications, and power connection systems and related methods |
US11236739B2 (en) | 2019-09-13 | 2022-02-01 | Bj Energy Solutions, Llc | Power sources and transmission networks for auxiliary equipment onboard hydraulic fracturing units and associated methods |
US11767791B2 (en) | 2019-09-13 | 2023-09-26 | Bj Energy Solutions, Llc | Mobile gas turbine inlet air conditioning system and associated methods |
US11761846B2 (en) | 2019-09-13 | 2023-09-19 | Bj Energy Solutions, Llc | Fuel, communications, and power connection systems and related methods |
US20230088221A1 (en) * | 2019-09-13 | 2023-03-23 | Bj Energy Solutions, Llc | Fuel, communications, and power connection systems and related methods |
US11649766B1 (en) | 2019-09-13 | 2023-05-16 | Bj Energy Solutions, Llc | Mobile gas turbine inlet air conditioning system and associated methods |
US11346280B1 (en) | 2019-09-13 | 2022-05-31 | Bj Energy Solutions, Llc | Direct drive unit removal system and associated methods |
US11415056B1 (en) | 2019-09-13 | 2022-08-16 | Bj Energy Solutions, Llc | Turbine engine exhaust duct system and methods for noise dampening and attenuation |
US11555756B2 (en) | 2019-09-13 | 2023-01-17 | Bj Energy Solutions, Llc | Fuel, communications, and power connection systems and related methods |
US11280266B2 (en) | 2019-09-13 | 2022-03-22 | Bj Energy Solutions, Llc | Mobile gas turbine inlet air conditioning system and associated methods |
US11287350B2 (en) | 2019-09-13 | 2022-03-29 | Bj Energy Solutions, Llc | Fuel, communications, and power connection methods |
US11613980B2 (en) | 2019-09-13 | 2023-03-28 | Bj Energy Solutions, Llc | Methods and systems for operating a fleet of pumps |
US11619122B2 (en) | 2019-09-13 | 2023-04-04 | Bj Energy Solutions, Llc | Methods and systems for operating a fleet of pumps |
US11401865B1 (en) | 2019-09-13 | 2022-08-02 | Bj Energy Solutions, Llc | Direct drive unit removal system and associated methods |
US11560848B2 (en) | 2019-09-13 | 2023-01-24 | Bj Energy Solutions, Llc | Methods for noise dampening and attenuation of turbine engine |
US11719234B2 (en) | 2019-09-13 | 2023-08-08 | Bj Energy Solutions, Llc | Systems and method for use of single mass flywheel alongside torsional vibration damper assembly for single acting reciprocating pump |
US11319878B2 (en) | 2019-09-13 | 2022-05-03 | Bj Energy Solutions, Llc | Direct drive unit removal system and associated methods |
US11268346B2 (en) | 2019-09-13 | 2022-03-08 | Bj Energy Solutions, Llc | Fuel, communications, and power connection systems |
US11746637B2 (en) | 2019-09-20 | 2023-09-05 | Yantai Jereh Petroleum Equipment & Technologies Co., Ltd. | Adaptive mobile power generation system |
US11702919B2 (en) | 2019-09-20 | 2023-07-18 | Yantai Jereh Petroleum Equipment & Technologies Co., Ltd. | Adaptive mobile power generation system |
US11788519B2 (en) | 2019-09-20 | 2023-10-17 | Yantai Jereh Petroleum Equipment & Technologies Co., Ltd. | Turbine fracturing equipment |
US11828277B2 (en) | 2019-09-20 | 2023-11-28 | Yantal Jereh Petroleum Equipment & Technologies Co., Ltd. | Turbine-driven fracturing system on semi-trailer |
US11519395B2 (en) | 2019-09-20 | 2022-12-06 | Yantai Jereh Petroleum Equipment & Technologies Co., Ltd. | Turbine-driven fracturing system on semi-trailer |
US20230146951A1 (en) * | 2019-10-03 | 2023-05-11 | U.S. Well Services, LLC | Electric powered hydraulic fracturing pump system with single electric powered multi-plunger fracturing pump |
US11905806B2 (en) * | 2019-10-03 | 2024-02-20 | U.S. Well Services, LLC | Electric powered hydraulic fracturing pump system with single electric powered multi-plunger fracturing pump |
US11459863B2 (en) * | 2019-10-03 | 2022-10-04 | U.S. Well Services, LLC | Electric powered hydraulic fracturing pump system with single electric powered multi-plunger fracturing pump |
US11920584B2 (en) * | 2020-03-12 | 2024-03-05 | American Jereh International Corporation | Continuous high-power turbine fracturing equipment |
US11913448B2 (en) | 2020-03-12 | 2024-02-27 | American Jereh International Corporation | Continuous high-power turbine fracturing equipment |
US20220120262A1 (en) * | 2020-03-12 | 2022-04-21 | American Jereh International Corporation | Continuous high-power turbine fracturing equipment |
US20210285432A1 (en) * | 2020-03-12 | 2021-09-16 | American Jereh International Corporation | Continous high-power turbine fracturing equipment |
US11873803B2 (en) * | 2020-03-12 | 2024-01-16 | American Jereh International Corporation | Continuous high-power turbine fracturing equipment |
US11635074B2 (en) | 2020-05-12 | 2023-04-25 | Bj Energy Solutions, Llc | Cover for fluid systems and related methods |
US11708829B2 (en) | 2020-05-12 | 2023-07-25 | Bj Energy Solutions, Llc | Cover for fluid systems and related methods |
US10968837B1 (en) | 2020-05-14 | 2021-04-06 | Bj Energy Solutions, Llc | Systems and methods utilizing turbine compressor discharge for hydrostatic manifold purge |
US11898504B2 (en) | 2020-05-14 | 2024-02-13 | Bj Energy Solutions, Llc | Systems and methods utilizing turbine compressor discharge for hydrostatic manifold purge |
US11434820B2 (en) | 2020-05-15 | 2022-09-06 | Bj Energy Solutions, Llc | Onboard heater of auxiliary systems using exhaust gases and associated methods |
US11428165B2 (en) | 2020-05-15 | 2022-08-30 | Bj Energy Solutions, Llc | Onboard heater of auxiliary systems using exhaust gases and associated methods |
US11624321B2 (en) | 2020-05-15 | 2023-04-11 | Bj Energy Solutions, Llc | Onboard heater of auxiliary systems using exhaust gases and associated methods |
US11698028B2 (en) | 2020-05-15 | 2023-07-11 | Bj Energy Solutions, Llc | Onboard heater of auxiliary systems using exhaust gases and associated methods |
US11959419B2 (en) | 2020-05-15 | 2024-04-16 | Bj Energy Solutions, Llc | Onboard heater of auxiliary systems using exhaust gases and associated methods |
US11542868B2 (en) | 2020-05-15 | 2023-01-03 | Bj Energy Solutions, Llc | Onboard heater of auxiliary systems using exhaust gases and associated methods |
US11208880B2 (en) | 2020-05-28 | 2021-12-28 | Bj Energy Solutions, Llc | Bi-fuel reciprocating engine to power direct drive turbine fracturing pumps onboard auxiliary systems and related methods |
US11313213B2 (en) | 2020-05-28 | 2022-04-26 | Bj Energy Solutions, Llc | Bi-fuel reciprocating engine to power direct drive turbine fracturing pumps onboard auxiliary systems and related methods |
US11365616B1 (en) | 2020-05-28 | 2022-06-21 | Bj Energy Solutions, Llc | Bi-fuel reciprocating engine to power direct drive turbine fracturing pumps onboard auxiliary systems and related methods |
US11814940B2 (en) | 2020-05-28 | 2023-11-14 | Bj Energy Solutions Llc | Bi-fuel reciprocating engine to power direct drive turbine fracturing pumps onboard auxiliary systems and related methods |
US11603745B2 (en) | 2020-05-28 | 2023-03-14 | Bj Energy Solutions, Llc | Bi-fuel reciprocating engine to power direct drive turbine fracturing pumps onboard auxiliary systems and related methods |
US11891952B2 (en) | 2020-06-05 | 2024-02-06 | Bj Energy Solutions, Llc | Systems and methods to enhance intake air flow to a gas turbine engine of a hydraulic fracturing unit |
US11627683B2 (en) | 2020-06-05 | 2023-04-11 | Bj Energy Solutions, Llc | Enclosure assembly for enhanced cooling of direct drive unit and related methods |
US11378008B2 (en) | 2020-06-05 | 2022-07-05 | Bj Energy Solutions, Llc | Systems and methods to enhance intake air flow to a gas turbine engine of a hydraulic fracturing unit |
US11300050B2 (en) | 2020-06-05 | 2022-04-12 | Bj Energy Solutions, Llc | Systems and methods to enhance intake air flow to a gas turbine engine of a hydraulic fracturing unit |
US11723171B2 (en) | 2020-06-05 | 2023-08-08 | Bj Energy Solutions, Llc | Enclosure assembly for enhanced cooling of direct drive unit and related methods |
US11746698B2 (en) | 2020-06-05 | 2023-09-05 | Bj Energy Solutions, Llc | Systems and methods to enhance intake air flow to a gas turbine engine of a hydraulic fracturing unit |
US11208953B1 (en) | 2020-06-05 | 2021-12-28 | Bj Energy Solutions, Llc | Systems and methods to enhance intake air flow to a gas turbine engine of a hydraulic fracturing unit |
US11129295B1 (en) | 2020-06-05 | 2021-09-21 | Bj Energy Solutions, Llc | Enclosure assembly for enhanced cooling of direct drive unit and related methods |
US11598264B2 (en) | 2020-06-05 | 2023-03-07 | Bj Energy Solutions, Llc | Systems and methods to enhance intake air flow to a gas turbine engine of a hydraulic fracturing unit |
US11109508B1 (en) | 2020-06-05 | 2021-08-31 | Bj Energy Solutions, Llc | Enclosure assembly for enhanced cooling of direct drive unit and related methods |
US10961908B1 (en) | 2020-06-05 | 2021-03-30 | Bj Energy Solutions, Llc | Systems and methods to enhance intake air flow to a gas turbine engine of a hydraulic fracturing unit |
US11261717B2 (en) | 2020-06-09 | 2022-03-01 | Bj Energy Solutions, Llc | Systems and methods for exchanging fracturing components of a hydraulic fracturing unit |
US11643915B2 (en) | 2020-06-09 | 2023-05-09 | Bj Energy Solutions, Llc | Drive equipment and methods for mobile fracturing transportation platforms |
US11015423B1 (en) | 2020-06-09 | 2021-05-25 | Bj Energy Solutions, Llc | Systems and methods for exchanging fracturing components of a hydraulic fracturing unit |
US11022526B1 (en) | 2020-06-09 | 2021-06-01 | Bj Energy Solutions, Llc | Systems and methods for monitoring a condition of a fracturing component section of a hydraulic fracturing unit |
US11939854B2 (en) | 2020-06-09 | 2024-03-26 | Bj Energy Solutions, Llc | Methods for detection and mitigation of well screen out |
US11066915B1 (en) | 2020-06-09 | 2021-07-20 | Bj Energy Solutions, Llc | Methods for detection and mitigation of well screen out |
US11566506B2 (en) | 2020-06-09 | 2023-01-31 | Bj Energy Solutions, Llc | Methods for detection and mitigation of well screen out |
US11085281B1 (en) | 2020-06-09 | 2021-08-10 | Bj Energy Solutions, Llc | Systems and methods for exchanging fracturing components of a hydraulic fracturing unit |
US11111768B1 (en) | 2020-06-09 | 2021-09-07 | Bj Energy Solutions, Llc | Drive equipment and methods for mobile fracturing transportation platforms |
US11867046B2 (en) | 2020-06-09 | 2024-01-09 | Bj Energy Solutions, Llc | Systems and methods for exchanging fracturing components of a hydraulic fracturing unit |
US11512570B2 (en) | 2020-06-09 | 2022-11-29 | Bj Energy Solutions, Llc | Systems and methods for exchanging fracturing components of a hydraulic fracturing unit |
US11174716B1 (en) | 2020-06-09 | 2021-11-16 | Bj Energy Solutions, Llc | Drive equipment and methods for mobile fracturing transportation platforms |
US11629583B2 (en) | 2020-06-09 | 2023-04-18 | Bj Energy Solutions, Llc | Systems and methods for exchanging fracturing components of a hydraulic fracturing unit |
US11208881B1 (en) | 2020-06-09 | 2021-12-28 | Bj Energy Solutions, Llc | Methods and systems for detection and mitigation of well screen out |
US10954770B1 (en) | 2020-06-09 | 2021-03-23 | Bj Energy Solutions, Llc | Systems and methods for exchanging fracturing components of a hydraulic fracturing unit |
US11319791B2 (en) | 2020-06-09 | 2022-05-03 | Bj Energy Solutions, Llc | Methods and systems for detection and mitigation of well screen out |
US11339638B1 (en) | 2020-06-09 | 2022-05-24 | Bj Energy Solutions, Llc | Systems and methods for exchanging fracturing components of a hydraulic fracturing unit |
US11639655B2 (en) | 2020-06-22 | 2023-05-02 | Bj Energy Solutions, Llc | Systems and methods to operate a dual-shaft gas turbine engine for hydraulic fracturing |
US11898429B2 (en) | 2020-06-22 | 2024-02-13 | Bj Energy Solutions, Llc | Systems and methods to operate a dual-shaft gas turbine engine for hydraulic fracturing |
US11208879B1 (en) | 2020-06-22 | 2021-12-28 | Bj Energy Solutions, Llc | Stage profiles for operations of hydraulic systems and associated methods |
US11125066B1 (en) | 2020-06-22 | 2021-09-21 | Bj Energy Solutions, Llc | Systems and methods to operate a dual-shaft gas turbine engine for hydraulic fracturing |
US11952878B2 (en) | 2020-06-22 | 2024-04-09 | Bj Energy Solutions, Llc | Stage profiles for operations of hydraulic systems and associated methods |
US11408263B2 (en) | 2020-06-22 | 2022-08-09 | Bj Energy Solutions, Llc | Systems and methods to operate a dual-shaft gas turbine engine for hydraulic fracturing |
US11732565B2 (en) | 2020-06-22 | 2023-08-22 | Bj Energy Solutions, Llc | Systems and methods to operate a dual-shaft gas turbine engine for hydraulic fracturing |
US11598188B2 (en) | 2020-06-22 | 2023-03-07 | Bj Energy Solutions, Llc | Stage profiles for operations of hydraulic systems and associated methods |
US11939853B2 (en) | 2020-06-22 | 2024-03-26 | Bj Energy Solutions, Llc | Systems and methods providing a configurable staged rate increase function to operate hydraulic fracturing units |
US11236598B1 (en) | 2020-06-22 | 2022-02-01 | Bj Energy Solutions, Llc | Stage profiles for operations of hydraulic systems and associated methods |
US11933153B2 (en) | 2020-06-22 | 2024-03-19 | Bj Energy Solutions, Llc | Systems and methods to operate hydraulic fracturing units using automatic flow rate and/or pressure control |
US11028677B1 (en) | 2020-06-22 | 2021-06-08 | Bj Energy Solutions, Llc | Stage profiles for operations of hydraulic systems and associated methods |
US11572774B2 (en) | 2020-06-22 | 2023-02-07 | Bj Energy Solutions, Llc | Systems and methods to operate a dual-shaft gas turbine engine for hydraulic fracturing |
US11719085B1 (en) | 2020-06-23 | 2023-08-08 | Bj Energy Solutions, Llc | Systems and methods to autonomously operate hydraulic fracturing units |
US11566505B2 (en) | 2020-06-23 | 2023-01-31 | Bj Energy Solutions, Llc | Systems and methods to autonomously operate hydraulic fracturing units |
US11428218B2 (en) | 2020-06-23 | 2022-08-30 | Bj Energy Solutions, Llc | Systems and methods of utilization of a hydraulic fracturing unit profile to operate hydraulic fracturing units |
US11939974B2 (en) | 2020-06-23 | 2024-03-26 | Bj Energy Solutions, Llc | Systems and methods of utilization of a hydraulic fracturing unit profile to operate hydraulic fracturing units |
US11661832B2 (en) | 2020-06-23 | 2023-05-30 | Bj Energy Solutions, Llc | Systems and methods to autonomously operate hydraulic fracturing units |
US11466680B2 (en) | 2020-06-23 | 2022-10-11 | Bj Energy Solutions, Llc | Systems and methods of utilization of a hydraulic fracturing unit profile to operate hydraulic fracturing units |
US11415125B2 (en) | 2020-06-23 | 2022-08-16 | Bj Energy Solutions, Llc | Systems for utilization of a hydraulic fracturing unit profile to operate hydraulic fracturing units |
US11649820B2 (en) | 2020-06-23 | 2023-05-16 | Bj Energy Solutions, Llc | Systems and methods of utilization of a hydraulic fracturing unit profile to operate hydraulic fracturing units |
US11473413B2 (en) | 2020-06-23 | 2022-10-18 | Bj Energy Solutions, Llc | Systems and methods to autonomously operate hydraulic fracturing units |
US11542802B2 (en) | 2020-06-24 | 2023-01-03 | Bj Energy Solutions, Llc | Hydraulic fracturing control assembly to detect pump cavitation or pulsation |
US11692422B2 (en) | 2020-06-24 | 2023-07-04 | Bj Energy Solutions, Llc | System to monitor cavitation or pulsation events during a hydraulic fracturing operation |
US11668175B2 (en) | 2020-06-24 | 2023-06-06 | Bj Energy Solutions, Llc | Automated diagnostics of electronic instrumentation in a system for fracturing a well and associated methods |
US11255174B2 (en) | 2020-06-24 | 2022-02-22 | Bj Energy Solutions, Llc | Automated diagnostics of electronic instrumentation in a system for fracturing a well and associated methods |
US11220895B1 (en) | 2020-06-24 | 2022-01-11 | Bj Energy Solutions, Llc | Automated diagnostics of electronic instrumentation in a system for fracturing a well and associated methods |
US11391137B2 (en) | 2020-06-24 | 2022-07-19 | Bj Energy Solutions, Llc | Systems and methods to monitor, detect, and/or intervene relative to cavitation and pulsation events during a hydraulic fracturing operation |
US11506040B2 (en) | 2020-06-24 | 2022-11-22 | Bj Energy Solutions, Llc | Automated diagnostics of electronic instrumentation in a system for fracturing a well and associated methods |
US11299971B2 (en) | 2020-06-24 | 2022-04-12 | Bj Energy Solutions, Llc | System of controlling a hydraulic fracturing pump or blender using cavitation or pulsation detection |
US11512571B2 (en) | 2020-06-24 | 2022-11-29 | Bj Energy Solutions, Llc | Automated diagnostics of electronic instrumentation in a system for fracturing a well and associated methods |
US11149533B1 (en) | 2020-06-24 | 2021-10-19 | Bj Energy Solutions, Llc | Systems to monitor, detect, and/or intervene relative to cavitation and pulsation events during a hydraulic fracturing operation |
US11746638B2 (en) | 2020-06-24 | 2023-09-05 | Bj Energy Solutions, Llc | Automated diagnostics of electronic instrumentation in a system for fracturing a well and associated methods |
US11274537B2 (en) | 2020-06-24 | 2022-03-15 | Bj Energy Solutions, Llc | Method to detect and intervene relative to cavitation and pulsation events during a hydraulic fracturing operation |
US11193361B1 (en) | 2020-07-17 | 2021-12-07 | Bj Energy Solutions, Llc | Methods, systems, and devices to enhance fracturing fluid delivery to subsurface formations during high-pressure fracturing operations |
US11603744B2 (en) | 2020-07-17 | 2023-03-14 | Bj Energy Solutions, Llc | Methods, systems, and devices to enhance fracturing fluid delivery to subsurface formations during high-pressure fracturing operations |
US11920450B2 (en) | 2020-07-17 | 2024-03-05 | Bj Energy Solutions, Llc | Methods, systems, and devices to enhance fracturing fluid delivery to subsurface formations during high-pressure fracturing operations |
US11365615B2 (en) | 2020-07-17 | 2022-06-21 | Bj Energy Solutions, Llc | Methods, systems, and devices to enhance fracturing fluid delivery to subsurface formations during high-pressure fracturing operations |
US11193360B1 (en) | 2020-07-17 | 2021-12-07 | Bj Energy Solutions, Llc | Methods, systems, and devices to enhance fracturing fluid delivery to subsurface formations during high-pressure fracturing operations |
US11255175B1 (en) | 2020-07-17 | 2022-02-22 | Bj Energy Solutions, Llc | Methods, systems, and devices to enhance fracturing fluid delivery to subsurface formations during high-pressure fracturing operations |
US11608727B2 (en) | 2020-07-17 | 2023-03-21 | Bj Energy Solutions, Llc | Methods, systems, and devices to enhance fracturing fluid delivery to subsurface formations during high-pressure fracturing operations |
US11994014B2 (en) | 2020-07-17 | 2024-05-28 | Bj Energy Solutions, Llc | Methods, systems, and devices to enhance fracturing fluid delivery to subsurface formations during high-pressure fracturing operations |
US11608726B2 (en) | 2021-01-11 | 2023-03-21 | Yantai Jereh Petroleum Equipment & Technologies Co., Ltd. | Switchable apparatus, well site and control method thereof, device, and storage medium |
US11867045B2 (en) | 2021-05-24 | 2024-01-09 | Bj Energy Solutions, Llc | Hydraulic fracturing pumps to enhance flow of fracturing fluid into wellheads and related methods |
US11639654B2 (en) | 2021-05-24 | 2023-05-02 | Bj Energy Solutions, Llc | Hydraulic fracturing pumps to enhance flow of fracturing fluid into wellheads and related methods |
US11732563B2 (en) | 2021-05-24 | 2023-08-22 | Bj Energy Solutions, Llc | Hydraulic fracturing pumps to enhance flow of fracturing fluid into wellheads and related methods |
US20230151723A1 (en) * | 2021-11-18 | 2023-05-18 | Yantai Jereh Petroleum Equipment & Technologies Co., Ltd. | Turbine Fracturing Apparatus and Turbine Fracturing Well Site |
Also Published As
Publication number | Publication date |
---|---|
CA3042189C (en) | 2022-09-06 |
CA3042189A1 (en) | 2019-11-04 |
Similar Documents
Publication | Publication Date | Title |
---|---|---|
CA3042189C (en) | Mobile pump system | |
US20210131410A1 (en) | Mobile Pump System | |
AU2018253528B2 (en) | Refueling method for supplying fuel to fracturing equipment | |
WO2019126742A1 (en) | Refueling method for supplying fuel to fracturing equipment | |
US8789609B2 (en) | Submersible hydraulic artificial lift systems and methods of operating same | |
US20130306322A1 (en) | System and process for extracting oil and gas by hydraulic fracturing | |
RU2353750C2 (en) | Composite power installation "three-in-one" for nitrogen system, for liquid system of fluid medium and for system with pump-compressor pipe wound on drum | |
US20140124208A1 (en) | Liquified petroleum gas fracturing system | |
US10106396B1 (en) | Refueling method for supplying fuel to fracturing equipment | |
CN103089196B (en) | Setting method and the device thereof joining work with abrasive perforating of bridging plug is carried out with oil pipe | |
CN104481488A (en) | Partial pressure annular pressure control method of plumb shaft coiled tubing sand filling | |
CN101929330A (en) | Remote control cock type steel ball delivery system | |
CN109441400B (en) | Device and method for removing and preventing wax of gas lift oil production well | |
CN201650255U (en) | Remote-control cock type steel ball injector | |
CN204098872U (en) | Electric immersible pump well tubing string and electric immersible pump well | |
CN109899013A (en) | A kind of horizontal well cable transmission waterpower pump-down tool Antisand sticking apparatus and method | |
CA3080744C (en) | Mobile, modular, electrically powered system for use in fracturing underground formations using liquid petroleum gas | |
US20240117725A1 (en) | Remotely-controlled pressure bleed-off system | |
Wendler et al. | Deep Water Well Testing for Heavy-and Low-Pour-Point Oils-Issues, Options, Successful Methodology: Case Histories | |
Al-Somali et al. | SS-Application Of Artificial Lift Technology In The Giant Khurais Field | |
CN110748325A (en) | Production pipe column and using method thereof |
Legal Events
Date | Code | Title | Description |
---|---|---|---|
AS | Assignment |
Owner name: RED LION CAPITAL PARTNERS, LLC, PENNSYLVANIA Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:CURRY, MATTHEW;COMBS, CHRISTOPHER;REEL/FRAME:049096/0286 Effective date: 20190504 |
|
STPP | Information on status: patent application and granting procedure in general |
Free format text: DOCKETED NEW CASE - READY FOR EXAMINATION |
|
STPP | Information on status: patent application and granting procedure in general |
Free format text: NON FINAL ACTION MAILED |
|
STPP | Information on status: patent application and granting procedure in general |
Free format text: FINAL REJECTION MAILED |
|
AS | Assignment |
Owner name: GREEN ZONE TECHNOLOGIES LLC, PENNSYLVANIA Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:RED LION CAPITAL PARTNERS, LLC;REEL/FRAME:055830/0361 Effective date: 20201216 |
|
STPP | Information on status: patent application and granting procedure in general |
Free format text: DOCKETED NEW CASE - READY FOR EXAMINATION |
|
STPP | Information on status: patent application and granting procedure in general |
Free format text: NON FINAL ACTION MAILED |
|
STPP | Information on status: patent application and granting procedure in general |
Free format text: RESPONSE TO NON-FINAL OFFICE ACTION ENTERED AND FORWARDED TO EXAMINER |
|
STPP | Information on status: patent application and granting procedure in general |
Free format text: FINAL REJECTION MAILED |
|
STCB | Information on status: application discontinuation |
Free format text: ABANDONED -- FAILURE TO RESPOND TO AN OFFICE ACTION |